10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________________________________________

FORM 10-Q

______________________________________________________________________________________

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to _____________                    

Commission File Number: 1-32225

_____________________________________________________________________________________

HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 ______________________________________________________________________________________

Delaware	20-0833098
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2828 N. Harwood, Suite 1300 Dallas, Texas	75201
(Address of principal executive offices)	(Zip code)

(214) 871-3555

(Registrant’s telephone number, including area code)

________________________________________________________________

(Former name, former address and former fiscal year, if changed since last report)

________________________________________________________________

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

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

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

Large accelerated filer	ý	Accelerated filer	¨	Non-accelerated filer	¨	Smaller reporting company	¨
Emerging growth company	¨

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

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

The number of the registrant’s outstanding common units at July 27, 2018, was 105,440,201.

Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

INDEX

	FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION			4
	Item 1.	Financial Statements (Unaudited)	4
		Consolidated Balance Sheets	4
		Consolidated Statements of Income	5
		Consolidated Statements of Comprehensive Income	6
		Consolidated Statements of Cash Flows	7
		Consolidated Statement of Equity	8
		Notes to Consolidated Financial Statements	9
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
	Item 4.	Controls and Procedures	46
PART II. OTHER INFORMATION			47
	Item 1.	Legal Proceedings	47
	Item 1A.	Risk Factors	47
	Item 6.	Exhibits	47
		Index to Exhibits	48
		SIGNATURES	48

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Table of Contentsril 19,

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations” and “Liquidity and Capital Resources” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I are forward-looking statements. Forward-looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “should,” “would,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. All statements concerning our expectations for future results of operations are based on forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

• risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled, stored or throughput in our terminals;

• the economic viability of HollyFrontier Corporation (“HFC”), Delek US Holdings, Inc. (“Delek”) and our other customers;

• the demand for refined petroleum products in markets we serve;

• our ability to purchase and integrate future acquired operations;

• our ability to complete previously announced or contemplated acquisitions;

• the availability and cost of additional debt and equity financing;

• the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;

• the effects of current and future government regulations and policies;

• our operational efficiency in carrying out routine operations and capital construction projects;

• the possibility of terrorist or cyber attacks and the consequences of any such attacks;

• general economic conditions;

• the impact of recent changes in the tax laws and regulations that affect master limited partnerships; and

• other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including, without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the known material risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2017, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in “Risk Factors.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Table of Contentsril 19,

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

	June 30, 2018		December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	6,656	$	7,776
Accounts receivable:
Trade	13,501		12,803
Affiliates	36,665		51,501
	50,166		64,304
Prepaid and other current assets	3,146		2,311
Total current assets	59,968		74,391
Properties and equipment, net	1,551,709		1,569,471
Intangible assets, net	121,935		129,463
Goodwill	270,336		266,716
Equity method investments	84,752		85,279
Other assets	27,363		28,794
Total assets	$	2,116,063	$	2,154,114
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	9,148	$	14,547
Affiliates	11,250		7,725
	20,398		22,272
Accrued interest	13,189		13,256
Deferred revenue	10,845		9,598
Accrued property taxes	5,540		4,652
Other current liabilities	3,593		5,707
Total current liabilities	53,565		55,485
Long-term debt	1,395,599		1,507,308
Other long-term liabilities	15,526		15,843
Deferred revenue	48,405		47,272
Class B unit	44,600		43,141
Equity:
Partners’ equity:
Common unitholders (105,440,201 and 101,568,955 units issued and outstanding     at June 30, 2018 and December 31, 2017, respectively)	468,397		393,959
Noncontrolling interest	89,971		91,106
Total equity	558,368		485,065
Total liabilities and equity	$	2,116,063	$	2,154,114

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In thousands, except per unit data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Affiliates	$	94,013		$	93,152		$	195,441		$	182,177
Third parties	24,747			15,991			52,203			32,600
	118,760			109,143			247,644			214,777
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	34,533			34,097			70,735			66,586
Depreciation and amortization	24,608			19,945			49,750			38,722
General and administrative	2,673			2,615			5,795			5,249
	61,814			56,657			126,280			110,557
Operating income	56,946			52,486			121,364			104,220
Other income (expense):
Equity in earnings of equity method investments	1,734			4,053			3,013			5,893
Interest expense	(17,626		)	(13,748		)	(35,207		)	(27,287		)
Interest income	526			103			1,041			205
Loss on early extinguishment of debt	—			—			—			(12,225		)
Gain (loss) on sale of assets and other	(53		)	89			33			162
	(15,419		)	(9,503		)	(31,120		)	(33,252		)
Income before income taxes	41,527			42,983			90,244			70,968
State income tax benefit (expense)	(28		)	(127		)	(110		)	(233		)
Net income	41,499			42,856			90,134			70,735
Allocation of net income attributable to noncontrolling interests	(1,356		)	(1,521		)	(3,823		)	(3,837		)
Net income attributable to the partners	40,143			41,335			86,311			66,898
General partner interest in net income attributable to the Partnership, including incentive distributions	—			(18,328		)	—			(35,466		)
Limited partners’ interest in net income	$	40,143		$	23,007		$	86,311		$	31,432
Limited partners’ per unit interest in earnings—basic and diluted	$	0.38		$	0.36		$	0.82		$	0.49
Weighted average limited partners’ units outstanding	105,429			64,086			104,637			63,602

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Net income	$	41,499		$	42,856		$	90,134		$	70,735
Other comprehensive income:
Change in fair value of cash flow hedging instruments	—			11			—			87
Reclassification adjustment to net income on partial settlement of cash flow hedge	—			(102		)	—			(115		)
Other comprehensive income	—			(91		)	—			(28		)
Comprehensive income before noncontrolling interest	41,499			42,765			90,134			70,707
Allocation of comprehensive income to noncontrolling interests	(1,356		)	(1,521		)	(3,823		)	(3,837		)
Comprehensive income attributable to the partners	$	40,143		$	41,244		$	86,311		$	66,870

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended June 30,
	2018			2017
Cash flows from operating activities
Net income	$	90,134		$	70,735
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	49,750			38,722
Gain on sale of assets	(183		)	(133		)
Amortization of deferred charges	1,516			1,504
Equity-based compensation expense	1,550			1,109
Equity in earnings of equity method investments, net of distributions	228			594
Loss on early extinguishment of debt	—			12,225
(Increase) decrease in operating assets:
Accounts receivable—trade	(698		)	(285		)
Accounts receivable—affiliates	14,836			6,033
Prepaid and other current assets	(835		)	(234		)
Increase (decrease) in operating liabilities:
Accounts payable—trade	(1,428		)	104
Accounts payable—affiliates	3,546			(9,128		)
Accrued interest	(67		)	(7,519		)
Deferred revenue	3,700			1,653
Accrued property taxes	888			(1,001		)
Other current liabilities	(2,023		)	(442		)
Other, net	49			(336		)
Net cash provided by operating activities	160,963			113,601
Cash flows from investing activities
Additions to properties and equipment	(24,739		)	(20,524		)
Business and asset acquisitions	(6,831		)	—
Proceeds from sale of assets	196			635
Distributions in excess of equity in earnings of equity investments	299			1,654
Net cash used for investing activities	(31,075		)	(18,235		)
Cash flows from financing activities
Borrowings under credit agreement	305,500			479,000
Repayments of credit agreement borrowings	(417,500		)	(189,000		)
Redemption of 6.5% Senior Notes	—			(309,750		)
Proceeds from issuance of common units	114,831			52,634
Distributions to HEP unitholders	(130,075		)	(112,195		)
Distributions to noncontrolling interest	(3,500		)	(3,500		)
Distribution to HFC for El Dorado tanks	—			(103		)
Contributions from general partner	492			995
Units withheld for tax withholding obligations	(58		)	(35		)
Other	(698		)	(730		)
Net cash used by financing activities	(131,008		)	(82,684		)
Cash and cash equivalents
Increase (decrease) for the period	(1,120		)	12,682
Beginning of period	7,776			3,657
End of period	$	6,656		$	16,339

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

(In thousands)

	Common Units			Noncontrolling Interest			Total Equity
Balance December 31, 2017	$	393,959		$	91,106		$	485,065
Issuance of common units	114,900			—			114,900
Distributions to HEP unitholders	(130,075		)	—			(130,075		)
Distributions to noncontrolling interest	—			(3,500		)	(3,500		)
Amortization of restricted and performance units	1,550			—			1,550
Class B unit accretion	(1,459		)	—			(1,459		)
Cumulative transition adjustment for adoption of revenue recognition standard	1,320			—			1,320
Other	433			—			433
Net income	87,769			2,365			90,134
Balance June 30, 2018	$	468,397		$	89,971		$	558,368

See accompanying notes.

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Table of Contentsril 19,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1: Description of Business and Presentation of Financial Statements

Holly Energy Partners, L.P. (“HEP”), together with its consolidated subsidiaries, is a publicly held master limited partnership. As of June 30, 2018, HollyFrontier Corporation (“HFC”) and its subsidiaries own a 57% limited partner interest and the non-economic general partner interest in HEP. We commenced operations on July 13, 2004, upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights (“IDRs”) held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions. As a result of this transaction, no distributions were made on the general partner interest after October 31, 2017.

On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partner interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under our revolving credit facility.

We own and operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support HFC’s refining and marketing operations in the Mid-Continent, Southwest and Northwest regions of the United States and Delek US Holdings, Inc.’s (“Delek”) refinery in Big Spring, Texas. Additionally, we own a 75% interest in UNEV Pipeline, LLC (“UNEV”), a 50% interest in the Osage Pipe Line Company, LLC (“Osage”) and a 50% interest in the Cheyenne Pipeline LLC.

We operate in two reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note 15.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons, providing other services at our storage tanks and terminals and by charging fees for processing hydrocarbon feedstocks through our refinery processing units. We do not take ownership of products that we transport, terminal, store or process, and therefore, we are not exposed directly to changes in commodity prices.

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2017. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2018.

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of subsidiaries and joint ventures that we control. All significant intercompany transactions and balances have been eliminated.

Most of our acquisitions from HFC occurred while we were a consolidated variable interest entity (“VIE”) of HFC. Therefore, as an entity under common control with HFC, we recorded these acquisitions on our balance sheets at HFC's historical basis instead of our purchase price or fair value.

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Accounting Pronouncements Adopted During the Periods Presented

Share-Based Compensation

In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for

tax withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in our operating activities. The impact of this change for the six months ended June 30, 2017 was not material to our consolidated statement of cash flows. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard had an effective date of January 1, 2018, and we accounted for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment was recorded to retained earnings as of the date of initial application. In preparing

for adoption, we evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we implemented policies to comply with this new standard. See Note 3 for additional information on our revenue recognition policies.

Business Combinations

In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accounting for identifiable intangible assets in business combinations. This standard had an effective date of January 1, 2018, and had no effect on our financial condition, results of operations or cash flows.

Financial Assets and Liabilities

In January 2016, an accounting standard update was issued requiring changes in the accounting and disclosures for financial instruments. This standard was effective beginning with our 2018 reporting year and had no effect on our financial condition, results of operations or cash flows.

Accounting Pronouncements Not Yet Adopted

Leases

In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. In preparing for adoption, we have identified, reviewed and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired software and are implementing systems to facilitate lease capture and related accounting treatment.

Note 2: Acquisitions

SLC Pipeline and Frontier Aspen

On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline LLC (“SLC Pipeline”) and the remaining 50% interest in Frontier Aspen LLC (“Frontier Aspen”) from subsidiaries of Plains All American Pipeline, L,P. (“Plains”), for cash consideration of $250 million. Prior to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a result of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.

These acquisitions were accounted for as a business combination achieved in stages. Our pre-existing equity method investments in SLC Pipeline and Frontier Aspen were remeasured at an acquisition date fair value of $112 million since we now have a controlling interest, and we recognized a gain on the remeasurement in the fourth quarter of 2017 of $36.3 million. The fair value of our pre-existing equity method investments in SLC Pipeline and Frontier Aspen was estimated using Level 3 Inputs under the income method for these entities, adjusted for lack of control and marketability.

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The total consideration of $363.8 million, consisting of initial cash consideration of $250 million, working capital adjustments of $1.8 million and the fair value of our preexisting equity method investments in SLC Pipeline and Frontier Aspen of $112 million, was allocated to the acquisition date fair value of assets and liabilities acquired as of the October 31, 2017 acquisition date, with the excess purchase price recorded as goodwill. The following summarizes the value of assets and liabilities acquired:

	(in thousands)
Cash and cash equivalents	$	4,609
Accounts receivable	5,164
Prepaid and other current assets	8
Properties and equipment	275,061
Intangible assets	70,182
Goodwill	13,845
Accounts payable	(3,598		)
Accrued property taxes	(1,438		)
Net assets acquired	$	363,833

SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal

of the Frontier Pipeline (defined below) and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah (the “Frontier Pipeline”) that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.

Note 3: Revenues

Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) it is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. Therefore, we bifurcate the consideration received between lease and service revenue. The service component is within the scope of Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09.

Several of our contracts include incentive or reduced tariffs once a certain quarterly volume is met. Revenue from the variable element of these transactions is recognized based on the actual volumes shipped as it relates specifically to rendering the services during the applicable quarter.

We adopted the new revenue recognition standard (see Note 1) using the modified retrospective method, whereby the cumulative effect of applying the new standard was recorded as an adjustment to the opening balance of retained earnings as well as the carrying amounts of assets and liabilities as of January 1, 2018, which had no impact on our cash flows. The following table reflects the cumulative effect of adoption as of January 1, 2018:

	Prior to Adoption		Increase (Decrease)			As Adjusted
	(In millions)
Deferred revenue	$	9,598	$	(1,320	)	$	8,278
Partners’ equity: Common unitholders	$	393,959	$	1,320		$	395,279

The majority of our long-term transportation contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of shipments in the event a customer ships below their contractual requirements. If there are no future performance obligations, we will recognize these deficiency payments in revenue.

In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize the service portion of these deficiency payments in revenue when we do not expect we will be required to satisfy these performance obligations in the future based on the pattern of rights exercised by the customer. During

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the three and six months ended June 30, 2018, we recognized $3.4 million and $7.0 million, respectively, of these deficiency payments in revenue, of which $0.4 million and $2.6 million, respectively, related to deficiency payments billed in prior periods. As of June 30, 2018, deferred revenue reflected in our consolidated balance sheet related to shortfalls billed was $4.4 million.

	June 30, 2018			January 1, 2018
	(In thousands)
Contract asset	$	1,562		$	—
Contract liability	$	(4,441	)	$	(2,713	)

The contract assets and liabilities include both lease and service components. We recognized $0.4 million and $2.6 million in revenue during the three and six months ended June 30, 2018, respectively, that was previously included in contract liability as of January 1, 2018.

As of June 30, 2018, we expect to recognize $2.4 billion in revenue related to our unfulfilled performance obligations under the terms of our long-term throughput agreements and operating leases expiring in 2019 through 2036. These agreements provide for changes in the minimum revenue guarantees annually for increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index, with certain contracts having provisions that limit the level of the rate increases or decreases. We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and lease revenues):

Years Ending December 31,	(In millions)
Remainder of 2018	$	188
2019	352
2020	305
2021	294
2022	267
Thereafter	1,042
Total	$	2,448

Payment terms under our contracts with customers are consistent with industry norms and are typically payable within 10 to 30 days of the date of invoice.

Disaggregated revenues are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
Pipelines	$	65,539	$	55,248	$	137,708	$	107,695
Terminals, tanks and loading racks	34,386		36,356		72,567		70,163
Refinery processing units	18,835		17,539		37,369		36,919
	$	118,760	$	109,143	$	247,644	$	214,777

During the three and six months ended June 30, 2018, lease revenues amounted to $68.1 million and $138.7 million, respectively, and service revenues amounted to $50.7 million and $109.0 million, respectively. Both of these revenues were recorded within affiliates and third parties revenues on our consolidated statement of income.

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Note 4: Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of these instruments. Debt consists of outstanding principal under our revolving credit agreement (which approximates fair value as interest rates are reset frequently at current interest rates) and our fixed interest rate senior notes.

Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

• (Level 1) Quoted prices in active markets for identical assets or liabilities.

• (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

• (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

The carrying amounts and estimated fair values of our senior notes were as follows:

		June 30, 2018				December 31, 2017
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Liabilities:
6% Senior notes	Level 2	495,599		507,025		495,308		525,120
		$	495,599	$	507,025	$	495,308	$	525,120

Level 2 Financial Instruments

Our senior notes are measured at fair value using Level 2 inputs. The fair value of the senior notes is based on market values provided by a third-party bank, which were derived using market quotes for similar type debt instruments. See Note 8 for additional information.

Note 5: Properties and Equipment

The carrying amounts of our properties and equipment are as follows:

	June 30, 2018		December 31, 2017
	(In thousands)
Pipelines, terminals and tankage	$	1,525,033	$	1,541,722
Refinery assets	347,338		347,338
Land and right of way	85,960		86,484
Construction in progress	42,811		12,029
Other	40,420		35,659
	2,041,562		2,023,232
Less accumulated depreciation	489,853		453,761
	$	1,551,709	$	1,569,471

We capitalized $0.2 million and $0.4 million during the six months ended June 30, 2018 and 2017, respectively, in interest attributable to construction projects.

Depreciation expense was $41.9 million and $34.9 million for the six months ended June 30, 2018 and 2017, respectively, and includes depreciation of assets acquired under capital leases.

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Note 6: Intangible Assets

Intangible assets include transportation agreements and customer relationships that represent a portion of the total purchase price of certain assets acquired from Delek in 2005, from HFC in 2008 prior to HEP becoming a consolidated VIE of HFC and from Plains in 2017.

The carrying amounts of our intangible assets are as follows:

	Useful Life	June 30, 2018		December 31, 2017
		(In thousands)
Delek transportation agreement	30 years	$	59,933	$	59,933
HFC transportation agreement	10-15 years	75,131		75,131
Customer relationships	10 years	69,282		69,282
Other		50		50
		204,396		204,396
Less accumulated amortization		82,461		74,933
		$	121,935	$	129,463

Amortization expense was $7.5 million and $3.5 million for the six months ended June 30, 2018 and 2017, respectively. We estimate amortization expense to be $14.0 million for each of the next four years and $9.8 million in 2023.

We have additional transportation agreements with HFC resulting from historical transactions consisting of pipeline, terminal and tankage assets contributed to us or acquired from HFC. These transactions occurred while we were a consolidated VIE of HFC; therefore, our basis in these agreements is zero and does not reflect a step-up in basis to fair value.

Note 7: Employees, Retirement and Incentive Plans

Direct support for our operations is provided by Holly Logistic Services, L.L.C. (“HLS”), an HFC subsidiary, which utilizes personnel employed by HFC who are dedicated to performing services for us. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $1.6 million and $1.3 million for the three months ended June 30, 2018 and 2017, respectively, and $3.4 million and $3.0 million for the six months ended June 30, 2018 and 2017, respectively.

Under HLS’s secondment agreement with HFC (the “Secondment Agreement”), certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs related to these employees.

We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted or phantom units, performance units, unit options and unit appreciation rights. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (a significant proportion of our awards) is to expense the costs ratably over the vesting periods.

As of June 30, 2018, we had two types of incentive-based awards outstanding, which are described below. The compensation cost charged against income was $0.7 million and $0.6 million for the three months ended June 30, 2018 and 2017, respectively, and $1.5 million and $0.9 million for the six months ended June 30, 2018 and 2017, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of June 30, 2018, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,323,787 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.

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Restricted and Phantom Units

Under our Long-Term Incentive Plan, we grant restricted units to non-employee directors and phantom units to selected employees who perform services for us, with most awards vesting over a period of one to three years. We previously granted restricted units to selected employees who perform services for us, which vest over a period of three years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution rights on these units from the date of grant, and the recipients of the restricted units have voting rights on the restricted units from the date of grant.

The fair value of each restricted or phantom unit award is measured at the market price as of the date of grant and is amortized on a straight-line basis over the requisite service period for each separately vesting portion of the award.

A summary of restricted and phantom unit activity and changes during the six months ended June 30, 2018, is presented below:

Restricted and Phantom Units	Units		Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2018 (nonvested)	119,009		$	34.77
Granted	12,890		30.23
Forfeited	(698	)	34.59
Outstanding at June 30, 2018 (nonvested)	131,201		$	34.33

No restricted units were vested and transferred to recipients during the six months ended June 30, 2018. As of June 30, 2018, there was $1.8 million of total unrecognized compensation expense related to unvested restricted and phantom unit grants, which is expected to be recognized over a weighted-average period of 1.2 years.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected officers who perform services for us. Performance units granted are payable in common units at the end of a three-year performance period based upon the growth in our distributable cash flow per common unit over the performance period. As of June 30, 2018, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target number of performance units granted.

We granted 2,764 performance units during the six months ended June 30, 2018. Performance units granted in 2017 and 2018 vest over a three-year performance period ending December 31, 2020 and 2021, respectively, and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, and can range from 50% to 150% of the target number of performance units granted. Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the common units from the date of grant.

A summary of performance unit activity and changes for the six months ended June 30, 2018, is presented below:

Performance Units	Units
Outstanding at January 1, 2018 (nonvested)	36,911
Granted	2,764
Vesting and transfer of common units to recipients	(4,283	)
Outstanding at June 30, 2018 (nonvested)	35,392

The grant date fair value of performance units vested and transferred to recipients during both the six months ended June 30, 2018 and 2017 was $0.1 million. Based on the weighted-average fair value of performance units outstanding at June 30, 2018, of $1.2 million, there was $0.7 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.6 years.

During the six months ended June 30, 2018, we did not purchase any common units in the open market for the issuance and

settlement of unit awards under our Long-Term Incentive Plan.

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Note 8: Debt

Credit Agreement

We have a $1.4 billion senior secured revolving credit facility (the “Credit Agreement”) expiring in July 2022. The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Credit Agreement is also available to fund letters of credit up to a $50 million sub-limit, and it contains an accordion feature giving us the ability to increase the size of the facility by up to $300 million with additional lender commitments.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets, and indebtedness under the Credit Agreement is guaranteed by our material, wholly-owned subsidiaries.  The Credit Agreement requires us to maintain compliance with certain financial covenants consisting of total leverage, senior secured leverage, and interest coverage.  It also limits or restricts our ability to engage in certain activities.  If, at any time prior to the expiration of the Credit Agreement, HEP obtains two investment grade credit ratings, the Credit Agreement will become unsecured and many of the covenants, limitations, and restrictions will be eliminated.

We may prepay all loans at any time without penalty, except for tranche breakage costs.  If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies.  We were in compliance with the covenants as of June 30, 2018.

Senior Notes

On July 19, 2016, we closed a private placement of $400 million in aggregate principal amount of 6% senior unsecured notes due in 2024 (the “ 6% Senior Notes”). On September 22, 2017, we closed a private placement of an additional $100 million in aggregate principal amount of the 6% Senior Notes for a combined aggregate principal amount outstanding of $500 million maturing in 2024.

The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of June 30, 2018. At any time when the 6% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6% Senior Notes.

Indebtedness under the 6% Senior Notes is guaranteed by our wholly-owned subsidiaries.

On January 4, 2017, we redeemed the $300 million aggregate principal amount of 6.5% senior notes due in 2020 (the “6.5% Senior Notes”) at a redemption cost of $309.8 million at which time we recognized a $12.2 million early extinguishment loss consisting of a $9.8 million debt redemption premium and unamortized discount and financing costs of $2.4 million. We funded the redemption with borrowings under our Credit Agreement.

Long-term Debt

The carrying amounts of our long-term debt are as follows:

	June 30, 2018			December 31, 2017
	(In thousands)
Credit Agreement
Amount outstanding	$	900,000		$	1,012,000
6% Senior Notes
Principal	500,000			500,000
Unamortized premium and debt issuance costs	(4,401		)	(4,692		)
	495,599			495,308
Total long-term debt	$	1,395,599		$	1,507,308

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Interest Rate Risk Management

The two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement advances matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Six Months Ended June 30,
	2018		2017
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	17,850	$	13,299
6.5% Senior Notes	—		162
6% Senior Notes	15,000		12,000
Amortization of discount and deferred debt issuance costs	1,516		1,536
Commitment fees and other	1,007		720
Total interest incurred	35,373		27,717
Less capitalized interest	166		430
Net interest expense	$	35,207	$	27,287
Cash paid for interest	$	33,935	$	33,700

Capital Lease Obligations

We have capital lease obligations related to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under capital leases was $5.7 million and $5.1 million as of June 30, 2018 and December 31, 2017, respectively, with accumulated depreciation of $3.7 million and $3.3 million as of June 30, 2018 and December 31, 2017, respectively. We include depreciation of capital leases in depreciation and amortization in our consolidated statements of income.

Note 9: Significant Customers

All revenues are domestic revenues, of which 86% are currently generated from our two largest customers: HFC and Delek.

The following table presents the percentage of total revenues generated by each of these customers:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
HFC	79	%	85	%	79	%	85	%
Delek	7	%	6	%	6	%	7	%

Note 10: Related Party Transactions

We serve HFC’s refineries under long-term pipeline, terminal and tankage throughput agreements, and refinery processing unit tolling agreements expiring from 2019 to 2036. Under these agreements, HFC agrees to transport, store and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminals, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual rate adjustments on July 1st each year generally based on increases or decreases in PPI or the FERC index. As of June 30, 2018, these agreements with HFC require minimum annualized payments to us of $334.5 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of these agreements, a shortfall payment may be applied as a credit in the following four quarters after its minimum obligations are met.

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Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee (currently $2.5 million) for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are charged to us separately by HFC. Also, we reimburse HFC and its affiliates for direct expenses they incur on our behalf.

Related party transactions with HFC are as follows:

• Revenues received from HFC were $94.0 million and $93.2 million for the three months ended June 30, 2018 and 2017, respectively, and $195.4 million and $182.2 million for the six months ended June 30, 2018 and 2017, respectively.

• HFC charged us general and administrative services under the Omnibus Agreement of $0.6 million for each of the three months ended June 30, 2018 and 2017, and $1.2 million for the six months ended June 30, 2018 and 2017.

• We reimbursed HFC for costs of employees supporting our operations of $12.5 million and $11.4 million for the three months ended June 30, 2018 and 2017, respectively, and $25.2 million and $22.9 million for the six months ended June 30, 2018 and 2017, respectively.

• HFC reimbursed us $2.9 million and $1.5 million for the three months ended June 30, 2018 and 2017, respectively, for expense and capital projects and $4.2 million and $2.8 million for the six months ended June 30, 2018 and 2017, respectively.

• We distributed $36.6 million and $72.8 million in the three and six months ended June 30, 2018, respectively, to HFC as regular distributions on its common units and $32.6 million and $63.9 million on its common units and general partner interest, including general partner incentive distributions, in the three and six months ended June 30, 2017, respectively.

• Accounts receivable from HFC were $36.7 million and $51.5 million at June 30, 2018, and December 31, 2017, respectively.

• Accounts payable to HFC were $11.3 million and $7.7 million at June 30, 2018, and December 31, 2017, respectively.

• Deferred revenue in the consolidated balance sheets at June 30, 2018 and December 31, 2017, includes $1.7 million and $4.4 million, respectively, relating to certain shortfall billings to HFC. It is possible that HFC may not exceed its minimum obligations to receive credit for any of the $1.7 million deferred at June 30, 2018.

• We received lease payments from HFC for use of our Artesia and Tulsa railyards of $0.5 million and $0.1 million for the three months ended June 30, 2018 and 2017, respectively, and $1.0 million and $0.2 million for the six months ended June 30, 2018 and 2017, respectively.

• On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics, a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions.

Note 11: Partners’ Equity, Income Allocations and Cash Distributions

As of June 30, 2018, HFC held 59,630,030 of our common units, constituting a 57% limited partner interest in us, and held the

non-economic general partner interest. Additionally, HEP Logistics, our general partner, owned all incentive distribution rights through October 31, 2017, at which time we closed on an equity restructuring transaction with HEP Logistics pursuant to which the incentive distribution rights were canceled. See Note 1 for a description of this equity restructuring transaction.

On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partnership interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under our Credit Agreement.

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Continuous Offering Program

We have a continuous offering program under which we may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. For the six months ended June 30, 2018, HEP issued 171,246 units under this program, providing approximately $5.2 million in gross proceeds. As of June 30, 2018, HEP has issued 2,413,153 units under this program, providing $82.3 million in gross proceeds.

We intend to use our net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. Amounts repaid under our credit facility may be reborrowed from time to time.

Allocations of Net Income

Net income attributable to HEP is allocated to the partners based on their weighted-average ownership percentage during the period.

Prior to the equity restructuring of the general partner interest owned by HEP Logistics described in Note 1 that occurred on October 31, 2017, net income attributable to HEP was allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner included incentive distributions that were declared subsequent to quarter end. After incentive distributions and other priority allocations were allocated to the general partner, the remaining net income attributable to HEP was allocated to the partners based on their weighted-average ownership percentage during the period.

The following table presents the allocation of the general partner interest in net income for the periods presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
General partner interest in net income	$	—	$	827	$	—	$	1,338
General partner incentive distribution	—		17,501		—		34,128
Total general partner interest in net income	$	—	$	18,328	$	—	$	35,466

Cash Distributions

On July 19, 2018, we announced our cash distribution for the second quarter of 2018 of $0.66 per unit. The distribution is payable on all common units and will be paid August 9, 2018, to all unitholders of record on July 30, 2018. However, HEP Logistics will waive $2.5 million in limited partner cash distributions in accordance with the equity restructuring discussed in Note 1.

Prior to the equity restructuring of the general partner interest owned by HEP Logistics that occurred on October 31, 2017, our general partner, HEP Logistics, was entitled to incentive distributions if the amount we distributed with respect to any quarter exceeded specified target levels. After the restructuring of the general partner interest, the general partner interest was no longer entitled to any distributions.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands, except per unit data)
General partner interest in distribution	$	—	$	1,188	$	—	$	2,336
General partner incentive distribution	—		17,501		—		34,128
Total general partner distribution	—		18,689		—		36,464
Limited partner distribution	67,091		40,682		133,670		80,314
Total regular quarterly cash distribution	$	67,091	$	59,371	$	133,670	$	116,778
Cash distribution per unit applicable to limited partners	$	0.6600	$	0.6325	$	1.3150	$	1.2525

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As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to HEP because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to HEP. Additionally, if the asset contributions and acquisitions from HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost, in excess of HFC’s historical basis in the transferred assets, would have been recorded in our financial statements at the time of acquisition as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

Note 12: Net Income Per Limited Partner Unit

Net income per unit applicable to the limited partners is computed using the two-class method, since we have more than one participating security (common units and restricted units). Prior to the equity restructuring transaction described in Note 1, which was effective October 31, 2017, we had participating securities which included the aforementioned common units and restricted units as well as general partner units and IDRs. After the equity restructuring, the general partner interest was no longer entitled to any distributions, and none were made on the general partner interest after October 31, 2017.

To the extent net income attributable to the partners exceeds or is less than cash distributions, this difference is allocated to the partners based on their weighted-average ownership percentage during the period, after consideration of any priority allocations of earnings. Our dilutive securities, restricted units, are immaterial for all periods presented.

For purposes of applying the two-class method, including the allocation of cash distributions in excess of earnings, net income per limited partner unit is computed as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Net income attributable to the partners	$	40,143		$	41,335		$	86,311		$	66,898
Less: General partner’s distribution declared (including IDRs)	—			(18,689		)	—			(36,464		)
Limited partner’s distribution declared on common units	(67,091		)	(40,682		)	(133,670		)	(80,314		)
Distributions in excess of net income attributable to the partners	$	(26,948	)	$	(18,036	)	$	(47,359	)	$	(49,880	)

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	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Three Months Ended June 30, 2018
Net income attributable to the partners:
Distributions declared	$	—		$	67,091		$	67,091
Distributions in excess of net income attributable to the partners	—			(26,948		)	(26,948		)
Net income attributable to the partners	$	—		$	40,143		$	40,143
Weighted average limited partners' units outstanding				105,429
Limited partners' per unit interest in earnings - basic and diluted				$	0.38
Three Months Ended June 30, 2017
Net income attributable to the partners:
Distributions declared	$	18,689		$	40,682		$	59,371
Distributions in excess of net income attributable to the partners	(361		)	(17,675		)	(18,036		)
Net income attributable to the partners	$	18,328		$	23,007		$	41,335
Weighted average limited partners' units outstanding				64,086
Limited partners' per unit interest in earnings - basic and diluted				$	0.36

	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Six Months Ended June 30, 2018
Net income attributable to partnership:
Distributions declared	$	—		$	133,670		$	133,670
Distributions in excess of net income attributable to partnership	—			(47,359		)	(47,359		)
Net income attributable to partnership	$	—		$	86,311		$	86,311
Weighted average limited partners' units outstanding				104,637
Limited partners' per unit interest in earnings - basic and diluted				$	0.82
Six Months Ended June 30, 2017
Net income attributable to partnership:
Distributions declared	$	36,464		$	80,314		$	116,778
Distributions in excess of net income attributable to partnership	(998		)	(48,882		)	(49,880		)
Net income attributable to partnership	$	35,466		$	31,432		$	66,898
Weighted average limited partners' units outstanding				63,602
Limited partners' per unit interest in earnings - basic and diluted				$	0.49

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Note 13: Environmental

We expensed $0.3 million for the three and the six months ended June 30, 2018, for environmental remediation obligations, and we incurred no expenses for the three and six months ended June 30, 2017. The accrued environmental liability, net of expected recoveries from indemnifying parties, reflected in our consolidated balance sheets was $6.3 million and $6.5 million at June 30, 2018 and December 31, 2017, respectively, of which $4.7 million and $5.0 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time.

Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers. As of June 30, 2018 and December 31, 2017, our consolidated balance sheets included additional accrued environmental liabilities of $0.7 million and $0.8 million, respectively, for HFC indemnified liabilities, and other assets included equal and offsetting balances representing amounts due from HFC related to indemnifications for environmental remediation liabilities.

Note 14: Contingencies

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

Note 15: Operating Segments

Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in two operating segments: pipelines and terminals, and refinery processing units. These operating segments adhere to the accounting polices used for our consolidated financial statements.

The pipelines and terminals segment has been aggregated as both pipeline and terminals (1) have similar economic characteristics,(2) similarly provide logistics services of transportation and storage of petroleum products, (3) similarly support the petroleum refining business, including distribution of its products, (4) have principally the same customers and (5) are subject to similar regulatory requirements.

We evaluate the performance of each segment based on its respective operating income. Certain general and administrative expenses and interest and financing costs are excluded from segment operating income as they are not directly attributable to a specific operating segment. Identifiable assets are those used by the segment, whereas other assets are principally equity method investments, cash, deposits and other assets that are not associated with a specific reportable operating segment.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Pipelines and terminals - affiliate	$	75,178		$	75,613		$	158,072		$	145,258
Pipelines and terminals - third-party	24,747			15,991			52,203			32,600
Refinery processing units - affiliate	18,835			17,539			37,369			36,919
Total segment revenues	$	118,760		$	109,143		$	247,644		$	214,777
Segment operating income:
Pipelines and terminals	$	51,004		$	49,164		$	111,217		$	95,649
Refinery processing units	8,615			5,937			15,942			13,820
Total segment operating income	59,619			55,101			127,159			109,469
Unallocated general and administrative expenses	(2,673		)	(2,615		)	(5,795		)	(5,249		)
Interest and financing costs, net	(17,100		)	(13,645		)	(34,166		)	(39,307		)
Equity in earnings of unconsolidated affiliates	1,734			4,053			3,013			5,893
Gain (loss) on sale of assets and other	(53		)	89			33			162
Income before income taxes	$	41,527		$	42,983		$	90,244		$	70,968
Capital Expenditures:
Pipelines and terminals	$	12,127		$	12,157		$	24,739		$	20,286
Refinery processing units	—			102			—			238
Total capital expenditures	$	12,127		$	12,259		$	24,739		$	20,524

	June 30, 2018		December 31, 2017
	(in thousands)
Identifiable assets:
Pipelines and terminals (1)	$	1,697,531	$	1,728,074
Refinery processing units	321,191		328,585
Other	97,341		97,455
Total identifiable assets	$	2,116,063	$	2,154,114

(1) Includes goodwill of $270.3 million and $266.7 million as of June 30, 2018 and December 31, 2017, respectively.

- 23 -

Note 16: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of HEP (“Parent”) under the 6% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect 100% owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional, subject to certain customary release provisions. These circumstances include (i) when a Guarantor Subsidiary is sold or sells all or substantially all of its assets, (ii) when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, (iii) when a Guarantor Subsidiary’s guarantee of other indebtedness is terminated or released and (iv) when the requirements for legal defeasance or covenant defeasance or to discharge the senior notes have been satisfied.

The following financial information presents condensed consolidating balance sheets, statements of comprehensive income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting.

Condensed Consolidating Balance Sheet

June 30, 2018	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	640	$	6,014	$	—		$	6,656
Accounts receivable	—		45,447		5,305		(586		)	50,166
Prepaid and other current assets	156		2,629		361		—			3,146
Total current assets	158		48,716		11,680		(586		)	59,968
Properties and equipment, net	—		1,197,968		353,741		—			1,551,709
Investment in subsidiaries	1,866,892		269,911		—		(2,136,803		)	—
Intangible assets, net	—		121,935		—		—			121,935
Goodwill	—		270,336		—		—			270,336
Equity method investments	—		84,752		—		—			84,752
Other assets	10,483		16,880		—		—			27,363
Total assets	$	1,877,533	$	2,010,498	$	365,421	$	(2,137,389	)	$	2,116,063
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	19,284	$	1,700	$	(586	)	$	20,398
Accrued interest	13,189		—		—		—			13,189
Deferred revenue	—		9,675		1,170		—			10,845
Accrued property taxes	—		3,077		2,463		—			5,540
Other current liabilities	88		3,505		—		—			3,593
Total current liabilities	13,277		35,541		5,333		(586		)	53,565
Long-term debt	1,395,599		—		—		—			1,395,599
Other long-term liabilities	260		15,060		206		—			15,526
Deferred revenue	—		48,405		—		—			48,405
Class B unit	—		44,600		—		—			44,600
Equity - partners	468,397		1,866,892		269,911		(2,136,803		)	468,397
Equity - noncontrolling interest	—		—		89,971		—			89,971
Total liabilities and equity	$	1,877,533	$	2,010,498	$	365,421	$	(2,137,389	)	$	2,116,063

- 24 -

Condensed Consolidating Balance Sheet

December 31, 2017	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	511	$	7,263	$	—		$	7,776
Accounts receivable	—		59,448		5,038		(182		)	64,304
Prepaid and other current assets	13		2,016		282		—			2,311
Total current assets	15		61,975		12,583		(182		)	74,391
Properties and equipment, net	—		1,213,626		355,845		—			1,569,471
Investment in subsidiaries	1,902,285		273,319		—		(2,175,604		)	—
Intangible assets, net	—		129,463		—		—			129,463
Goodwill	—		266,716		—		—			266,716
Equity method investments	—		85,279		—		—			85,279
Other assets	11,753		17,041		—		—			28,794
Total assets	$	1,914,053	$	2,047,419	$	368,428	$	(2,175,786	)	$	2,154,114
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	20,928	$	1,526	$	(182	)	$	22,272
Accrued interest	12,500		756		—		—			13,256
Deferred revenue	—		8,540		1,058		—			9,598
Accrued property taxes	—		3,431		1,221		—			4,652
Other current liabilities	—		5,707		—		—			5,707
Total current liabilities	12,500		39,362		3,805		(182		)	55,485
Long-term debt	1,507,308		—		—		—			1,507,308
Other long-term liabilities	286		15,359		198		—			15,843
Deferred revenue	—		47,272		—		—			47,272
Class B unit	—		43,141		—		—			43,141
Equity - partners	393,959		1,902,285		273,319		(2,175,604		)	393,959
Equity - noncontrolling interest	—		—		91,106		—			91,106
Total liabilities and equity	$	1,914,053	$	2,047,419	$	368,428	$	(2,175,786	)	$	2,154,114

- 25 -

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	89,522		$	4,491		$	—		$	94,013
Third parties	—			19,540			5,207			—			24,747
	—			109,062			9,698			—			118,760
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			31,494			3,039			—			34,533
Depreciation and amortization				20,431			4,177			—			24,608
General and administrative	761			1,912			—			—			2,673
	761			53,837			7,216			—			61,814
Operating income (loss)	(761		)	55,225			2,482			—			56,946
Other income (expense):
Equity in earnings of subsidiaries	58,566			1,881			—			(60,447		)	—
Equity in earnings of equity method investments	—			1,734			—			—			1,734
Interest expense	(17,662		)	36			—			—			(17,626		)
Interest income	—			526			—			—			526
Gain on sale of assets and other	—			(79		)	26			—			(53		)
	40,904			4,098			26			(60,447		)	(15,419		)
Income before income taxes	40,143			59,323			2,508			(60,447		)	41,527
State income tax expense	—			(28		)	—			—			(28		)
Net income	40,143			59,295			2,508			(60,447		)	41,499
Allocation of net income attributable to noncontrolling interests	—			(729		)	(627		)	—			(1,356		)
Net income attributable to the partners	40,143			58,566			1,881			(60,447		)	40,143
Other comprehensive income	—			—			—			—			—
Comprehensive income attributable to the partners	$	40,143		$	58,566		$	1,881		$	(60,447	)	$	40,143

- 26 -

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	88,022		$	5,130		$	—		$	93,152
Third parties	—			10,385			5,606			—			15,991
	—			98,407			10,736			—			109,143
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			30,871			3,226			—			34,097
Depreciation and amortization	—			15,791			4,154			—			19,945
General and administrative	865			1,750			—			—			2,615
	865			48,412			7,380			—			56,657
Operating income (loss)	(865		)	49,995			3,356			—			52,486
Other income (expense):
Equity in earnings of subsidiaries	48,375			2,519			—			(50,894		)	—
Equity in earnings of equity method investments	—			4,053			—			—			4,053
Interest expense	(6,175		)	(7,573		)	—			—			(13,748		)
Interest income	—			103			—			—			103
Gain on sale of assets and other	—			87			2			—			89
	42,200			(811		)	2			(50,894		)	(9,503		)
Income before income taxes	41,335			49,184			3,358			(50,894		)	42,983
State income tax expense	—			(127		)	—			—			(127		)
Net income	41,335			49,057			3,358			(50,894		)	42,856
Allocation of net income attributable to noncontrolling interests	—			(682		)	(839		)	—			(1,521		)
Net income attributable to the partners	41,335			48,375			2,519			(50,894		)	41,335
Other comprehensive income	(91		)	(91		)	—			91			(91		)
Comprehensive income attributable to the partners	$	41,244		$	48,284		$	2,519		$	(50,803	)	$	41,244

- 27 -

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	183,813		$	11,628		$	—		$	195,441
Third parties	—			39,518			12,685			—			52,203
	—			223,331			24,313			—			247,644
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			64,158			6,577			—			70,735
Depreciation and amortization	—			41,432			8,318			—			49,750
General and administrative	2,041			3,754			—			—			5,795
	2,041			109,344			14,895			—			126,280
Operating income (loss)	(2,041		)	113,987			9,418			—			121,364
Other income (expense):
Equity in earnings (loss) of subsidiaries	123,618			7,093			—			(130,711		)	—
Equity in earnings of equity method investments	—			3,013			—			—			3,013
Interest expense	(35,311		)	104			—			—			(35,207		)
Interest income	—			1,041			—			—			1,041
Gain (loss) on sale of assets and other	45			(51		)	39			—			33
	88,352			11,200			39			(130,711		)	(31,120		)
Income (loss) before income taxes	86,311			125,187			9,457			(130,711		)	90,244
State income tax expense	—			(110		)	—			—			(110		)
Net income (loss)	86,311			125,077			9,457			(130,711		)	90,134
Allocation of net income attributable to noncontrolling interests	—			(1,459		)	(2,364		)	—			(3,823		)
Net income (loss) attributable to Holly Energy Partners	86,311			123,618			7,093			(130,711		)	86,311
Other comprehensive income (loss)	—			—			—			—			—
Comprehensive income (loss)	$	86,311		$	123,618		$	7,093		$	(130,711	)	$	86,311

- 28 -

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	168,798		$	13,379		$	—		$	182,177
Third parties	—			21,388			11,212			—			32,600
	—			190,186			24,591			—			214,777
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			59,963			6,623			—			66,586
Depreciation and amortization	—			30,644			8,078			—			38,722
General and administrative	2,020			3,229			—			—			5,249
	2,020			93,836			14,701			—			110,557
Operating income (loss)	(2,020		)	96,350			9,890			—			104,220
Other income (expense):
Equity in earnings (loss) of subsidiaries	93,658			7,420			—			(101,078		)	—
Equity in earnings of equity method investments	—			5,893			—			—			5,893
Interest expense	(12,515		)	(14,772		)	—			—			(27,287		)
Interest income	—			205			—			—			205
Loss on early extinguishment of debt	(12,225		)	—			—			—			(12,225		)
Gain (loss) on sale of assets and other	—			159			3			—			162
	68,918			(1,095		)	3			(101,078		)	(33,252		)
Income (loss) before income taxes	66,898			95,255			9,893			(101,078		)	70,968
State income tax expense	—			(233		)	—			—			(233		)
Net income (loss)	66,898			95,022			9,893			(101,078		)	70,735
Allocation of net income attributable to noncontrolling interests	—			(1,364		)	(2,473		)	—			(3,837		)
Net income (loss) attributable to Holly Energy Partners	66,898			93,658			7,420			(101,078		)	66,898
Other comprehensive income (loss)	(28		)	(28		)	—			28			(28		)
Comprehensive income (loss)	$	66,870		$	93,630		$	7,420		$	(101,050	)	$	66,870

- 29 -

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(33,588	)	$	182,983		$	18,661		$	(7,093	)	$	160,963
Cash flows from investing activities
Additions to properties and equipment	—			(18,829		)	(5,910		)	—			(24,739		)
Business and asset acquisitions	—			(6,831		)	—			—			(6,831		)
Distributions from UNEV in excess of earnings	—			3,407			—			(3,407		)	—
Proceeds from sale of assets	—			196			—			—			196
Distributions in excess of equity in earnings of equity investments	—			299			—			—			299
	—			(21,758		)	(5,910		)	(3,407		)	(31,075		)
Cash flows from financing activities
Net repayments under credit agreement	(112,000		)	—			—			—			(112,000		)
Net intercompany financing activities	160,330			(160,330		)	—			—			—
Proceeds from issuance of common units	114,899			(68		)	—			—			114,831
Contribution from general partner	492			—			—			—			492
Distributions to HEP unitholders	(130,075		)	—			—			—			(130,075		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Units withheld for tax withholding obligations	(58		)	—			—			—			(58		)
Other	—			(698		)	—			—			(698		)
	33,588			(161,096		)	(14,000		)	10,500			(131,008		)
Cash and cash equivalents
Increase (decrease) for the period	—			129			(1,249		)	—			(1,120		)
Beginning of period	2			511			7,263			—			7,776
End of period	$	2		$	640		$	6,014		$	—		$	6,656

- 30 -

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(20,377	)	$	122,025		$	19,373		$	(7,420	)	$	113,601
Cash flows from investing activities
Additions to properties and equipment	—			(17,670		)	(2,854		)	—			(20,524		)
Proceeds from sale of assets	—			635			—			—			635
Distributions from UNEV in excess of earnings	—			3,080			—			(3,080		)	—
Distributions in excess of equity in earnings of equity investments	—			1,654			—			—			1,654
	—			(12,301		)	(2,854		)	(3,080		)	(18,235		)
Cash flows from financing activities
Net borrowings under credit agreement	—			290,000			—			—			290,000
Net intercompany financing activities	389,005			(389,005		)	—			—			—
Redemption of senior notes	(309,750		)	—			—			—			(309,750		)
Proceeds from issuance of common units	52,383			251			—			—			52,634
Distributions to HEP unitholders	(112,195		)	—			—			—			(112,195		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Distribution to HFC for El Dorado tanks	(103		)	—			—			—			(103		)
Contributions from general partner	1,072			(77		)	—			—			995
Units withheld for tax withholding obligations	(35		)	—			—			—			(35		)
Other	—			(730		)	—			—			(730		)
	20,377			(99,561		)	(14,000		)	10,500			(82,684		)
Cash and cash equivalents
Decrease for the period	—			10,163			2,519			—			12,682
Beginning of period	2			301			3,354			—			3,657
End of period	$	2		$	10,464		$	5,873		$	—		$	16,339

- 31 -

Table of Contentsril 19,

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 2, including but not limited to the sections under “Results of Operations” and “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I of this Quarterly Report on Form 10-Q. In this document, the words “we,” “our,” “ours” and “us” refer to Holly Energy Partners, L.P. (“HEP”) and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

OVERVIEW

HEP is a Delaware limited partnership. We own and operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support the refining and marketing operations of HollyFrontier Corporation (“HFC”) in the Mid-Continent, Southwest and Northwest regions of the United States and Delek US Holdings, Inc.’s (“Delek”) refinery in Big Spring, Texas. HEP, through its subsidiaries and joint ventures, owns and/or operates petroleum product and crude pipelines, tankage and terminals in Texas, New Mexico, Arizona, Washington, Idaho, Oklahoma, Utah, Nevada, Wyoming and Kansas as well as refinery processing units in Utah and Kansas. HFC owned 57% of our outstanding common units and the non-economic general partnership interest, as of June 30, 2018.

On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights (“IDRs”) held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions. As a result of this transaction, no distributions were made on the general partner interest after October 31, 2017.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons, providing other services at our storage tanks and terminals and charging a tolling fee per barrel or thousand standard cubic feet of feedstock throughput in our refinery processing units. We do not take ownership of products that we transport, terminal, store or process, and therefore, we are not directly exposed to changes in commodity prices.

We believe the long-term growth of global refined product demand and U.S. crude production should support high utilization rates for the refineries we serve, which in turn will support volumes in our product pipelines, crude gathering systems and terminals.

Acquisitions

On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline LLC (“SLC Pipeline”) and the remaining 50% interest in Frontier Aspen LLC (“Frontier Aspen”) from subsidiaries of Plains All American Pipeline, L.P. (“Plains”), for cash consideration of $250 million. Prior to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a result of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.

This acquisition was accounted for as a business combination achieved in stages with the consideration allocated to the acquisition date fair value of assets and liabilities acquired. The preexisting equity interests in SLC Pipeline and Frontier Aspen were remeasured at acquisition date fair value since we have a controlling interest as a result, and we recognized a gain on the remeasurement in the fourth quarter of 2017 of $36.3 million.

SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal of the Frontier Pipeline and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.

Agreements with HFC and Delek

We serve HFC’s refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from 2019 to 2036. Under these agreements, HFC agrees to transport, store and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminal, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual rate adjustments on July 1st

- 32 -

Table of Contentsril 19,

each year, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of June 30, 2018, these agreements with HFC require minimum annualized payments to us of $335 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

We have a pipelines and terminals agreement with Delek expiring in 2020 under which Delek has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that is also subject to annual tariff rate adjustments. We also have a capacity lease agreement under which we lease Delek space on our Orla to El Paso pipeline for the shipment of refined product. The terms under this lease agreement expire beginning in the third quarter of 2018 through the first quarter of 2022. As of June 30, 2018, these agreements with Delek require minimum annualized payments to us of $33 million.

A significant reduction in revenues under these agreements could have a material adverse effect on our results of operations.

Under certain provisions of an omnibus agreement we have with HFC (“Omnibus Agreement”), we pay HFC an annual administrative fee, currently $2.5 million, for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of Holly Logistic Services, L.L.C. (“HLS”), or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.

Under HLS’s Secondment Agreement with HFC, certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs of these employees for our benefit.

We have a long-term strategic relationship with HFC. Our current growth plan is to continue to pursue purchases of logistic and other assets at HFC’s existing refining locations in New Mexico, Utah, Oklahoma, Kansas and Wyoming. We also expect to work with HFC on logistic asset acquisitions in conjunction with HFC’s refinery acquisition strategies. Furthermore, we plan to continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.

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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow, Volumes and Balance Sheet Data

The following tables present income, distributable cash flow and volume information for the six months ended June 30, 2018 and 2017.

	Three Months Ended June 30,						Change from
	2018			2017			2017
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	18,744		$	19,432		$	(688	)
Affiliates—intermediate pipelines	7,255			7,250			5
Affiliates—crude pipelines	18,479			16,919			1,560
	44,478			43,601			877
Third parties—refined product pipelines	12,348			11,647			701
Third parties—crude pipelines	8,713			—			8,713
	65,539			55,248			10,291
Terminals, tanks and loading racks:
Affiliates	30,700			32,012			(1,312		)
Third parties	3,686			4,344			(658		)
	34,386			36,356			(1,970		)
Affiliates—refinery processing units	18,835			17,539			1,296
Total revenues	118,760			109,143			9,617
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	34,533			34,097			436
Depreciation and amortization	24,608			19,945			4,663
General and administrative	2,673			2,615			58
	61,814			56,657			5,157
Operating income	56,946			52,486			4,460
Other income (expense):
Equity in earnings of equity method investments	1,734			4,053			(2,319		)
Interest expense, including amortization	(17,626		)	(13,748		)	(3,878		)
Interest income	526			103			423
Gain (loss) on sale of assets and other	(53		)	89			(142		)
	(15,419		)	(9,503		)	(5,916		)
Income before income taxes	41,527			42,983			(1,456		)
State income tax expense	(28		)	(127		)	99
Net income	41,499			42,856			(1,357		)
Allocation of net income attributable to noncontrolling interests	(1,356		)	(1,521		)	165
Net income attributable to the partners	40,143			41,335			(1,192		)
General partner interest in net income attributable to the partners (1)	—			(18,328		)	18,328
Limited partners’ interest in net income	$	40,143		$	23,007		$	17,136
Limited partners’ earnings per unit—basic and diluted(1)	$	0.38		$	0.36		$	0.36
Weighted average limited partners’ units outstanding	105,429			64,086			64,086
EBITDA(2)	$	81,879		$	75,052		$	6,827
Distributable cash flow(3)	$	65,180		$	60,908		$	4,272
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	112,371			134,357			(21,986		)
Affiliates—intermediate pipelines	151,537			151,683			(146		)
Affiliates—crude pipelines	322,850			269,418			53,432
	586,758			555,458			31,300
Third parties—refined product pipelines	73,196			71,612			1,584
Third parties – crude pipelines	115,011			—			115,011
	774,965			627,070			147,895
Terminals and loading racks:
Affiliates	446,089			461,329			(15,240		)
Third parties	59,035			67,657			(8,622		)
	505,124			528,986			(23,862		)
Affiliates—refinery processing units	71,117			67,310			3,807
Total for pipelines and terminal and refinery processing unit assets (bpd)	1,351,206			1,223,366			127,840

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	Six Months Ended June 30,						Change from
	2018			2017			2017
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	40,038		$	37,176		$	2,862
Affiliates—intermediate pipelines	15,724			12,534			3,190
Affiliates—crude pipelines	38,276			33,800			4,476
	94,038			83,510			10,528
Third parties—refined product pipelines	25,930			24,185			1,745
Third parties—crude pipelines	17,740			—			17,740
	137,708			107,695			30,013
Terminals, tanks and loading racks:
Affiliates	64,034			61,748			2,286
Third parties	8,533			8,415			118
	72,567			70,163			2,404
Affiliates—refinery processing units	37,369			36,919			450
Total revenues	247,644			214,777			32,867
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	70,735			66,586			4,149
Depreciation and amortization	49,750			38,722			11,028
General and administrative	5,795			5,249			546
	126,280			110,557			15,723
Operating income	121,364			104,220			17,144
Other income (expense):
Equity in earnings of equity method investments	3,013			5,893			(2,880		)
Interest expense, including amortization	(35,207		)	(27,287		)	(7,920		)
Interest income	1,041			205			836
Loss on early extinguishment of debt	—			(12,225		)	12,225
Gain on sale of assets and other	33			162			(129		)
	(31,120		)	(33,252		)	2,132
Income before income taxes	90,244			70,968			19,276
State income tax expense	(110		)	(233		)	123
Net income	90,134			70,735			19,399
Allocation of net income attributable to noncontrolling interests	(3,823		)	(3,837		)	14
Net income attributable to the partners	86,311			66,898			19,413
General partner interest in net income attributable to the partners (1)	—			(35,466		)	35,466
Limited partners’ interest in net income	$	86,311		$	31,432		$	54,879
Limited partners’ earnings per unit—basic and diluted(1)	$	0.82		$	0.49		$	0.33
Weighted average limited partners’ units outstanding	104,637			63,602			41,035
EBITDA(2)	$	170,337		$	132,935		$	37,402
Distributable cash flow(3)	$	134,279		$	118,197		$	16,082
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	128,498			120,886			7,612
Affiliates—intermediate pipelines	139,333			128,143			11,190
Affiliates—crude pipelines	341,922			269,155			72,767
	609,753			518,184			91,569
Third parties—refined product pipelines	72,720			78,339			(5,619		)
Third parties – crude pipelines	120,568			—			120,568
	803,041			596,523			206,518
Terminals and loading racks:
Affiliates	418,439			418,365			74
Third parties	60,684			68,646			(7,962		)
	479,123			487,011			(7,888		)
Affiliates—refinery processing units	69,008			65,082			3,926
Total for pipelines and terminal and refinery processing unit assets (bpd)	1,351,172			1,148,616			202,556

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(1) Prior to the equity restructuring transaction on October 31, 2017, net income attributable to Holly Energy Partners was allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner included incentive distributions that were declared subsequent to quarter end. There were no distributions made on the general partner interest after October 31, 2017, and general partner distributions were $18.7 million and $36.5 million for the three and six months ended June 30, 2017, respectively.

(2) Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to the partners plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income attributable to the partners or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. Set forth below is our calculation of EBITDA.

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Net income attributable to the partners	$	40,143		$	41,335		$	86,311		$	66,898
Add (subtract):
Interest expense	16,867			12,982			33,691			25,751
Interest income	(526		)	(103		)	(1,041		)	(205		)
Amortization of discount and deferred debt issuance costs	759			766			1,516			1,536
State income tax expense	28			127			110			233
Depreciation and amortization	24,608			19,945			49,750			38,722
EBITDA	$	81,879		$	75,052		$	170,337		$	132,935

(3) Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exceptions of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. Set forth below is our calculation of distributable cash flow.

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Net income attributable to the partners	$	40,143		$	41,335		$	86,311		$	66,898
Add (subtract):
Depreciation and amortization	24,608			19,945			49,750			38,722
Amortization of discount and deferred debt issuance costs	759			766			1,516			1,536
Loss on early extinguishment of debt	—			—			—			12,225
Customer billings greater than revenue recognized	1,819			1,524			138			2,701
Maintenance capital expenditures (4)	(987		)	(2,242		)	(1,305		)	(3,067		)
Decrease in environmental liability	(78		)	(313		)	(218		)	(559		)
Decrease in reimbursable deferred revenue	(1,243		)	(923		)	(2,420		)	(1,848		)
Other non-cash adjustments	159			816			507			1,589
Distributable cash flow	$	65,180		$	60,908		$	134,279		$	118,197

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(4) Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations.

	June 30, 2018		December 31, 2017
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	6,656	$	7,776
Working capital	$	6,403	$	18,906
Total assets	$	2,116,063	$	2,154,114
Long-term debt	$	1,395,599	$	1,507,308
Partners’ equity (5)	$	468,397	$	393,959

(5) As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to the partners because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to the partners. Additionally, if the assets contributed and acquired from HFC while we were a consolidated VIE of HFC had been acquired from third parties, our acquisition cost in excess of HFC’s basis in the transferred assets would have been recorded in our financial statements as increases to our properties and equipment and intangible assets at the time of acquisition instead of decreases to partners’ equity.

Results of Operations—Three Months Ended June 30, 2018 Compared with Three Months Ended June 30, 2017

Summary

Net income attributable to the partners for the second quarter was $40.1 million ($0.38 per basic and diluted limited partner unit) compared to $41.3 million ($0.36 per basic and diluted limited partner unit) for the second quarter of 2017. The decrease in earnings is primarily due to higher interest expense partially offset by higher crude pipeline throughputs and revenues.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Revenues for the three months ended June 30, 2018, include the recognition of $0.4 million of prior shortfalls billed to shippers in 2017 compared to revenues for the three months ended June 30, 2017, which included the recognition of $1.4 million of prior shortfalls billed to shippers in 2016 and 2017. Additional net shortfall billings of $2.3 million associated with certain guaranteed shipping contracts were deferred during the three months ended June 30, 2018.

Revenues

Revenues for the quarter were $118.8 million, an increase of $9.6 million compared to the second quarter of 2017. The increase is primarily attributable to our acquisition of the remaining interest in the SLC and Frontier pipelines, which led to an increase in overall pipeline volumes of 24%.

Revenues from our refined product pipelines were $31.1 million for both the second quarters of 2018 and 2017, and shipments averaged 185.6 thousand barrels per day (“mbpd”) compared to 206.0 mbpd for the second quarter of 2017. The volume decrease is mainly due to pipelines servicing HFC's Woods Cross refinery, which had lower throughput due to operational issues at the refinery. Revenue remained constant due to contractual minimum volume guarantees.

Revenues from our intermediate pipelines were $7.3 million for both the second quarters ended 2018 and 2017, on shipments averaging 151.5 mbpd compared to 151.7 mbpd for the second quarter of 2017.

Revenues from our crude pipelines were $27.2 million, an increase of $10.3 million, on shipments averaging 437.9 mbpd compared to 269.4 mbpd for the second quarter of 2017. The increases are mainly attributable to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017 as well as increased volumes on our crude pipeline systems in New Mexico and Texas.

Revenues from terminal, tankage and loading rack fees were $34.4 million, a decrease of $2.0 million compared to the second quarter of 2017. Refined products and crude oil terminalled in the facilities averaged 505.1 mbpd compared to 529.0 mbpd for

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the second quarter of 2017. The revenue and volume decreases are mainly due to lower volumes at terminals associated with UNEV Pipeline, LLC (“UNEV”) and lower volumes at our Tulsa tanks.

Revenues from refinery processing units were $18.8 million, an increase of $1.3 million on throughputs averaging 71.1 mbpd compared to 67.3 mbpd for the third quarter of 2017. The increase in revenue is mainly due to higher volumes at our Woods Cross refinery processing units.

Operations Expense

Operations (exclusive of depreciation and amortization) expense for the three months ended June 30, 2018, increased by $0.4 million compared to the three months ended June 30, 2017. The increase is primarily due to new operating costs and expenses related to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2018, increased by $4.7 million compared to the three months ended June 30, 2017. The increase is primarily due to depreciation and amortization related to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017.

General and Administrative

General and administrative costs for the three months ended June 30, 2018, increased by $0.1 million compared to the three months ended June 30, 2017, mainly due to higher employee compensation.

Equity in Earnings of Equity Method Investments

	Three Months Ended June 30,
Equity Method Investment	2018		2017
	(in thousands)
SLC Pipeline LLC	$	—	$	906
Frontier Aspen LLC	—		1,587
Osage Pipe Line Company, LLC	959		568
Cheyenne Pipeline LLC	775		992
Total	$	1,734	$	4,053

Interest Expense

Interest expense for the three months ended June 30, 2018, totaled $17.6 million, an increase of $3.9 million compared to the three months ended June 30, 2017. The increase is primarily due to interest expense associated with the private placement of an additional $100 million in aggregate principal amount of our 6% Senior Notes due in 2024 completed in the third quarter of 2017, higher average balances outstanding under our senior secured revolving credit facility, and market interest rate increases under that facility. Our aggregate effective interest rates were 5.0% and 4.4% for the three months ended June 30, 2018 and 2017, respectively.

State Income Tax

We recorded state income tax expense of $28,000 and $127,000 for the three months ended June 30, 2018 and 2017, respectively. All tax expense is solely attributable to the Texas margin tax.

Results of Operations—Six Months Ended June 30, 2018 Compared with Six Months Ended June 30, 2017

Summary

Net income attributable to Holly Energy Partners for the six months ended June 30, 2018, was $86.3 million compared to $66.9 million for the six months ended June 30, 2017. The increase in earnings is primarily due to higher pipeline throughputs and revenues as well as increased earnings related to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017, which were partially offset by higher interest expense. In addition, we recognized a loss on early extinguishment of debt of $12.2 million in the first quarter of 2017.

Revenues for the six months ended June 30, 2018, include the recognition of $2.6 million of prior shortfalls billed to shippers in 2017 compared to revenues for the six months ended June 30, 2017, which included the recognition of $3.5 million of prior shortfalls billed to shippers in 2016. As of June 30, 2018, deferred revenue reflected in our consolidated balance sheet related to shortfalls billed was $4.4 million.

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Revenues

Revenues for the six months ended June 30, 2018, were $247.6 million, an increase of $32.9 million compared to the six months ended June 30, 2017. The increase is primarily attributable to our acquisition of the remaining interest in the SLC and Frontier pipelines and the turnaround at HFC’s Navajo refinery in the first quarter of 2017.

Revenues from our refined product pipelines were $66.0 million, an increase of $4.6 million, on shipments averaging 201.2 mbpd compared to 199.2 mbpd for the six months ended June 30, 2017. Revenues increased due to the turnaround at HFC's Navajo refinery in the first quarter of 2017.

Revenues from our intermediate pipelines were $15.7 million, an increase of $3.2 million, on shipments averaging 139.3 mbpd compared to 128.1 mbpd for the six months ended June 30, 2017. These increases were principally due to the turnaround at HFC's Navajo refinery in the first quarter of 2017.

Revenues from our crude pipelines were $56.0 million, an increase of $22.2 million, on shipments averaging 462.5 mbpd compared to 269.2 mbpd for the six months ended June 30, 2017. The increases are mainly attributable to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017 as well as increased volumes on our crude pipeline systems in New Mexico and Texas.

Revenues from terminal, tankage and loading rack fees were $72.6 million, an increase of $2.4 million compared to the six months ended June 30, 2017. Refined products and crude oil terminalled in the facilities averaged 479.1 mbpd compared to 487.0 mbpd for the six months ended June 30, 2017. The increase in revenue is primarily due to higher volumes in several of our terminals as well as an adjustment in revenue recognition. Total volumes decreased mainly due to lower volumes at our Tulsa tanks, which are supported by minimum volume commitments.

Revenues from refinery processing units were $37.4 million, an increase of $0.5 million on throughputs averaging 69.0 mbpd compared to 65.1 mbpd for the six months ended June 30, 2017. The increase in revenue is mainly due to higher volumes at our Woods Cross refinery processing units.

Operations Expense

Operations expense (exclusive of depreciation and amortization) for the six months ended June 30, 2018, increased by $4.1 million compared to the six months ended June 30, 2017. The increase is primarily due to new operating costs and expenses related to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2018, increased by $11.0 million compared to the six months ended June 30, 2017. The increase is primarily due to depreciation and amortization related to our acquisition of the remaining interest in the SLC and Frontier pipelines in the fourth quarter of 2017.

General and Administrative

General and administrative costs for the six months ended June 30, 2018, increased $0.5 million compared to the six months ended June 30, 2017, mainly due to higher incentive compensation and professional fees.

Equity in Earnings of Equity Method Investments

	Six Months Ended June 30,
Equity Method Investments	2018		2017
	(in thousands)
SLC Pipeline LLC	$	—	$	1,024
Frontier Aspen LLC	—		2,151
Osage Pipe Line Company, LLC	1,601		770
Cheyenne Pipeline LLC	1,412		1,948
Total	$	3,013	$	5,893

Interest Expense

Interest expense for the six months ended June 30, 2018, totaled $35.2 million, an increase of $7.9 million compared to the six months ended June 30, 2017. The increase is primarily due to interest expense associated with the private placement of an

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additional $100 million in aggregate principal amount of our 6% Senior Notes due 2024 completed in the third quarter of 2017, higher average balances outstanding under our senior secured revolving credit facility, and market interest rate increases under that facility. Our aggregate effective interest rates were 5.0% and 4.3% for the six months ended June 30, 2018 and 2017, respectively.

Loss on Early Extinguishment of Debt

A loss on early extinguishment of debt of $12.2 million was recognized upon redemption of our $300 million aggregate principal amount of 6.5% Senior Notes at a cost of $309.8 million on January 4, 2017. The loss related to the premium paid to noteholders upon their tender of an aggregate principal amount of $300 million and related financing costs that were previously deferred.

State Income Tax

We recorded state income tax expense of $110,000 and $233,000 for the six months ended June 30, 2018 and 2017, respectively. All tax expense is solely attributable to the Texas margin tax.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We have a $1.4 billion senior secured revolving credit facility (the “Credit Agreement”) expiring in July 2022. The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Credit Agreement is also available to fund letters of credit up to a $50 million sub-limit, and it contains an accordion feature giving us the ability to increase the size of the facility by up to $300 million with additional lender commitments.

During the six months ended June 30, 2018, we received advances totaling $305.5 million and repaid $417.5 million, resulting in a net decrease of $112.0 million under the Credit Agreement and an outstanding balance of $900.0 million at June 30, 2018. As of June 30, 2018, we have no letters of credit outstanding under the Credit Agreement and the available capacity under the Credit Agreement was $500.0 million. Amounts repaid under our credit facility may be reborrowed from time to time.

If any particular lender under the Credit Agreement could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, we review publicly available information on the lenders in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We do not expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partnership interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under the Credit Agreement.

We have a continuous offering program under which we may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. For the six months ended June 30, 2018, HEP issued 171,246 units under this program, providing approximately $5.2 million in gross proceeds. We intend to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. As of June 30, 2018, HEP has issued 2,413,153 units under this program, providing $82.3 million in gross proceeds.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the authority to raise up to $2.0 billion, less amounts issued under the $200 million continuous offering program, by offering securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

We believe our current cash balances, future internally generated funds and funds available under the Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.

In May 2018, we paid a regular cash distribution of $0.6550 on all units in an aggregate amount of $66.6 million after deducting HEP Logistics' waiver of $2.5 million of limited partner cash distributions.

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Cash and cash equivalents decreased by $1.1 million during the six months ended June 30, 2018. The cash flows provided by operating activities of $161.0 million were less than the cash flows used for financing activities of $131.0 million and investing activities of $31.1 million. Working capital decreased by $12.5 million to $6.4 million at June 30, 2018, from $18.9 million at December 31, 2017.

Cash Flows—Operating Activities

Cash flows from operating activities increased by $47.4 million from $113.6 million for the six months ended June 30, 2017, to $161.0 million for the six months ended June 30, 2018. The increase is due primarily to increased receipts from customers during the six months ended June 30, 2018, as compared to the three months ended June 30, 2017.

Cash Flows—Investing Activities

Cash flows used for investing activities were $31.1 million for the six months ended June 30, 2018, compared to $18.2 million for the six months ended June 30, 2017, an increase of $12.8 million. During the six months ended June 30, 2018 and 2017, we invested $24.7 million and $20.5 million in additions to properties and equipment, respectively. During the six months ended June 30, 2018, we had cash payments of $6.8 million for acquisitions. During the six months ended June 30, 2018 and 2017, we also received $0.3 million and $1.7 million, respectively, for distributions in excess of equity in earnings of equity investments, respectively.

Cash Flows—Financing Activities

Cash flows used for financing activities were $131.0 million for the six months ended June 30, 2018, compared to $82.7 million for the six months ended June 30, 2017, an increase of $48.3 million. During the six months ended June 30, 2018, we received $305.5 million and repaid $417.5 million in advances under the Credit Agreement. We also received net proceeds of $114.8 million from the issuance of common units. Additionally, we paid $130.1 million in regular quarterly cash distributions to our limited partners and $3.5 million to our noncontrolling interest. During the six months ended June 30, 2017, we received $479.0 million and repaid $189.0 million in advances under the Credit Agreement. We redeemed our 6.5% Senior Notes at a redemption cost of $309.8 million. We paid $112.2 million in regular quarterly cash distributions to our general and limited partners, and distributed $3.5 million to our noncontrolling interest. We also received net proceeds of $52.6 million from the issuance of common units under our continuous offering program.

Capital Requirements

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures, reimbursable capital expenditures and expansion capital expenditures. “Maintenance capital expenditures” represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. “Reimbursable capital expenditures” are capital expenditure projects that are reimbursed by HFC or a third-party. “Expansion capital expenditures” represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the board of directors of HLS, our ultimate general partner, approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. We are forecasting to spend $8 million for maintenance capital expenditures, $5 million to $10 million for reimbursable capital expenditures and approximately $45 million to $55 million for expansion capital expenditures in 2018. We expect the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks, enhanced blending capabilities at our racks, and a new truck rack. In addition to our capital budget, we may spend funds periodically to perform capital upgrades or additions to our assets where a customer reimburses us for such costs. The upgrades or additions would generally benefit the customer over the remaining life of the related service agreements.

We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects, will be funded with cash generated by operations, the sale of additional limited partner common units, the issuance of debt securities and advances under our Credit Agreement, or a combination thereof. With volatility and

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uncertainty at times in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.

Under the terms of the transaction to acquire HFC’s 75% interest in UNEV, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2015, and ending in June 2032, subject to certain limitations. However, to the extent earnings thresholds are not achieved, no redemption payments are required. No redemption payments have been required related to the period ending June 30, 2018 or any other prior periods to date.

Credit Agreement

Our $1.4 billion Credit Agreement expires in July 2022. The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Credit Agreement is also available to fund letters of credit up to a $50 million sub-limit, and it contains an accordion feature giving us the ability to increase the size of the facility by up to $300 million with additional lender commitments.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets, and indebtedness under the Credit Agreement is guaranteed by our material, wholly-owned subsidiaries.  The Credit Agreement requires us to maintain compliance with certain financial covenants consisting of total leverage, senior secured leverage, and interest coverage.  It also limits or restricts our ability to engage in certain activities.  If, at any time prior to the expiration of the Credit Agreement, HEP obtains two investment grade credit ratings, the Credit Agreement will become unsecured and many of the covenants, limitations, and restrictions will be eliminated.

We may prepay all loans at any time without penalty, except for tranche breakage costs.  If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies.  We were in compliance with all covenants as of June 30, 2018.

Senior Notes

On January 4, 2017, we redeemed the $300 million aggregate principal amount of our 6.5% Senior Notes due 2020 at a redemption cost of $309.8 million, at which time we recognized a $12.2 million early extinguishment loss. We funded the redemption with borrowings under our Credit Agreement.

We have $500 million in aggregate principal amount of 6% Senior Notes due 2024. We used the net proceeds from our offerings of the 6% Senior Notes to repay indebtedness under our Credit Agreement.

The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of June 30, 2018. At any time when the 6% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6% Senior Notes.

Indebtedness under the 6% Senior Notes is guaranteed by our wholly-owned subsidiaries.

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Long-term Debt

The carrying amounts of our long-term debt are as follows:

	June 30, 2018			December 31, 2017
	(In thousands)
Credit Agreement	$	900,000		$	1,012,000
6% Senior Notes
Principal	500,000			500,000
Unamortized debt issuance costs	(4,401		)	(4,692		)
	495,599			495,308
Total long-term debt	$	1,395,599		$	1,507,308

See “Risk Management” for a discussion of our interest rate swaps.

Contractual Obligations

There were no significant changes to our long-term contractual obligations during this period.

Impact of Inflation

Inflation in the United States has been relatively moderate in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2018 and 2017. PPI has increased an average of 0.4% annually over the past five calendar years, including an increase of 3.2% and a decrease of 1.0% in 2017 and 2016, respectively.

The substantial majority of our revenues are generated under long-term contracts that provide for increases or decreases in our rates and minimum revenue guarantees annually for increases or decreases in the PPI. Certain of these contracts have provisions that limit the level of annual PPI percentage rate increases or decreases. A significant and prolonged period of high inflation or a significant and prolonged period of negative inflation could adversely affect our cash flows and results of operations if costs increase at a rate greater than the fees we charge our shippers.

Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.

We have an environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations.

There are environmental remediation projects in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities retained by HFC. At June 30, 2018, we had an accrual of $6.3 million that related to environmental clean-up projects for which we have assumed liability or for which the indemnity provided for by

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HFC has expired or will expire. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2017. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements include revenue recognition, assessing the possible impairment of certain long-lived assets and goodwill, and assessing contingent liabilities for probable losses. With the exception of our revenue recognition policies, there have been no changes to these policies in 2018. We consider these policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

Revenue Recognition: In May 2014, ASU 2014-09 “Revenue from Contracts with Customers” was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. We adopted this standard effective January 1, 2018, and therefore, have conformed our revenue recognition policies. See Note 3, “Revenues”, for additional information on our revenue recognition policies.

Accounting Pronouncements Adopted During the Periods Presented

Share-Based Compensation

In March 2016, an accounting standard update was issued that simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for tax-withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in operating activities. The impact of this change for the three months ended June 30, 2017 was not material to our consolidated statement of cash flows. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard had an effective date of January 1, 2018, and we have accounted for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment is recorded to retained earnings as of the date of initial application. In preparing

for adoption, we evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we implemented policies to comply with this new standard. See Note 3, “Revenues”, for additional information on our revenue recognition policies.

Business Combinations

In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accounting for identifiable intangible assets in business combinations. This standard had an effective date of January 1, 2018, and had no effect on our financial condition, results of operations or cash flows.

Financial Assets and Liabilities

In January 2016, an accounting standard update was issued requiring changes in the accounting and disclosures for financial instruments. This standard was effective beginning with our 2018 reporting year and had no effect on our financial condition, results of operations or cash flows.

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Accounting Pronouncements Not Yet Adopted

Leases

In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. In preparing for adoption, we have identified, reviewed and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired software and are implementing systems to facilitate lease capture and related accounting treatment.

RISK MANAGEMENT

The two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement advances matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.

The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.

At June 30, 2018, we had an outstanding principal balance of $500 million on our 6% Senior Notes. A change in interest rates generally would affect the fair value of the 6% Senior Notes, but not our earnings or cash flows. At June 30, 2018, the fair value of our 6% Senior Notes was $507.0 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6% Senior Notes at June 30, 2018, would result in a change of approximately $15 million in the fair value of the underlying 6% Senior Notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At June 30, 2018, borrowings outstanding under the Credit Agreement were $900.0 million. A hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

We have a risk management oversight committee that is made up of members from our senior management.  This committee monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our long-term debt, which disclosure should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have direct market risks associated with commodity prices.

Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2018, at a reasonable level of assurance.

(b) Changes in internal control over financial reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we may become party to legal, regulatory or administrative proceedings or governmental investigations, including environmental and other matters. Damages or penalties may be sought from us in some matters and certain matters may require years to resolve.  While the outcome and impact of these proceedings and investigations on us cannot be predicted with certainty, based on advice of counsel, management believes that the resolution of these proceedings and investigations, through settlement or adverse judgment, will not, either individually or in the aggregate, have a materially adverse effect on our financial condition, results of operations or cash flows.

Environmental Matters

We are reporting the following proceedings to comply with SEC regulations which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. Our respective subsidiaries have or will develop corrective action plans regarding the subject of these proceedings that will be implemented in consultation with the respective federal and state agencies. It is not possible to predict the ultimate outcome of these proceedings, although none are currently expected to have a material effect on our financial condition, results of operations or cash flows.

Written Safety Compliance Program

Holly Energy Partners - Operating, L.P. (“HEP Operating”) received a Notice of Probable Violation (NOPV) dated June 20, 2018 from the Pipeline and Hazardous Materials Safety Administration (“PHMSA”).  The NOPV follows a routine inspection of HEP's facilities and records and is not in response to an incident.  In the NOPV, PHMSA alleges certain regulatory violations involving HEP Operating’s written safety compliance program for its pipelines, terminals and tanks.  PHMSA has proposed a civil penalty and a compliance order that would require HEP Operating to take certain remedial actions.  HEP Operating is currently evaluating the merits of PHMSA's allegations.

Other

We are a party to various other legal and regulatory proceedings, which we believe, based on the advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.

Item 1A. Risk Factors

There have been no material changes in our risk factors as previously disclosed in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017. In addition to the other information set forth in this quarterly report, you should consider carefully the factors discussed in our 2017 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2017 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business, financial condition or future results.

Item 6. Exhibits

The Exhibit Index on page 47 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of this Quarterly Report on Form 10-Q.

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Exhibit Index

Exhibit Number	Description
3.1	Second Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on November 1, 2017, File No. 1-32225).
3.2	First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners - Operating Company, L.P. (incorporated by reference to Exhibit 3.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-32225).
3.3	First Amended and Restated Agreement of Limited Partnership of HEP Logistics Holdings, L.P. (incorporated by reference to Exhibit 3.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.4	First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 3.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.5	Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C., dated April 27, 2011 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report filed on May 3, 2011, File No. 1-32225).
3.6	First Amended and Restated Limited Liability Company Agreement of HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 3.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
4.1*	Third Supplemental Indenture, dated as of May 29, 2018, by and among HEP Oklahoma LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors party thereto, and U.S. Bank National Association.
10.1*	First Amendment to Third Amended and Restated Master Throughput Agreement, dated as of June 12, 2018, effective as of April 1, 2017, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners-Operating, L.P.
31.1*	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

101++ The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statement of Partners’ Equity, and (vi) Notes to Consolidated Financial Statements.

*	Filed herewith.
**	Furnished herewith.
++	Filed electronically herewith.

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	HOLLY ENERGY PARTNERS, L.P.
	(Registrant)
		By: HEP LOGISTICS HOLDINGS, L.P. its General Partner
		By: HOLLY LOGISTIC SERVICES, L.L.C. its General Partner
Date: August 2, 2018		/s/    Richard L. Voliva III
		Richard L. Voliva III
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: August 2, 2018		/s/    Kenneth P. Norwood
		Kenneth P. Norwood
		Vice President and Controller (Principal Accounting Officer)

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EX-4.1

Execution Version

THIRD SUPPLEMENTAL INDENTURE

THIRD SUPPLEMENTAL INDENTURE (this “Third Supplemental Indenture”), dated as of May 29, 2018, among HEP Oklahoma LLC, a Delaware limited liability company (the “Guaranteeing Subsidiary”), Holly Energy Partners, L.P., a Delaware limited partnership (“Holly Energy Partners”), and Holly Energy Finance Corp. (“Finance Corp.” and collectively with Holly Energy Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to herein (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of July 19, 2016, providing for the issuance of 6% Senior Notes due 2024 (the “Notes”), a First Supplemental Indenture, dated as of November 2, 2016, providing for the addition of Woods Cross Operating LLC, a Delaware limited liability company, as Guarantor under the Indenture and a Second Supplemental Indenture, dated as of July 26, 2017, providing for the addition of Holly Energy Holdings LLC, a Delaware limited liability company, and HEP Cheyenne Shortline LLC, a Delaware limited liability, as Guarantors under the Indenture;

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Third Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1.    CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2.    AGREEMENT TO GUARANTEE. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof.

3.    NO RECOURSE AGAINST OTHERS. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Third Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal

1

securities laws and it is the view of the U.S. Securities and Exchange Commission that such a waiver is against public policy.

4.    NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS THIRD SUPPLEMENTAL INDENTURE.

5.    COUNTERPARTS. The parties may sign any number of copies of this Third Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6.    EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof.

7.    THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Third Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

[Remainder of Page Intentionally Left Blank]

2

IN WITNESS WHEREOF, the parties hereto have caused this Third Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY:

HEP OKLAHOMA LLC, a Delaware limited liability company

By: /s/ John Harrison__________________________

John Harrison

Vice President and Treasurer

ISSUERS:

HOLLY ENERGY PARTNERS, L.P.

By: HEP Logistic Holdings, L.P.,
its general partner

By: Holly Logistic Services, L.L.C.,
its general partner

By: /s/ John Harrison__________________

John Harrison

Vice President and Treasurer

HOLLY ENERGY FINANCE CORP.

By: /s/ John Harrison__________________________

John Harrison

Vice President and Treasurer

S-3

OTHER GUARANTORS:

CHEYENNE LOGISTICS LLC, a Delaware limited liability company

EL DORADO LOGISTICS LLC, a Delaware limited liability company

EL DORADO OPERATING LLC, a Delaware limited liability company

EL DORADO OSAGE LLC, a Delaware limited liability company

FRONTIER ASPEN LLC, a Delaware limited liability company

HEP CHEYENNE LLC, a Delaware limited liability company

HEP CHEYENNE SHORTLINE LLC, a Delaware limited liability company

HEP EL DORADO LLC, a Delaware limited liability company

HEP LOGISTICS GP, L.L.C., a Delaware limited liability company

HEP MOUNTAIN HOME, L.L.C., a Delaware limited liability company

HEP PIPELINE, L.L.C., a Delaware limited liability company

HEP PIPELINE GP, L.L.C., a Delaware limited liability company

HEP REFINING, L.L.C., a Delaware limited liability company

HEP REFINING GP, L.L.C., a Delaware limited liability company

HEP TULSA LLC, a Delaware limited liability company

S-4

HEP UNEV HOLDINGS LLC, a Delaware limited liability company

HEP UNEV PIPELINE LLC, a Delaware limited liability company

HEP WOODS CROSS, L.L.C., a Delaware limited liability company

HOLLY ENERGY HOLDINGS LLC, a Delaware limited liability company

HOLLY ENERGY PARTNERS-OPERATING, L.P., a Delaware limited partnership

HOLLY ENERGY STORAGE—LOVINGTON LLC, a Delaware limited liability company

LOVINGTON-ARTESIA, L.L.C.,a Delaware limited liability company

ROADRUNNER PIPELINE, L.L.C., a Delaware limited liability company

SLC PIPELINE LLC, a Delaware limited liability company

WOODS CROSS OPERATING LLC, a Delaware limited liability company

HEP FIN-TEX/TRUST RIVER, L.P., a Texas limited partnership

HEP PIPELINE ASSETS, LIMITED PARTNERSHIP, a Delaware limited partnership

HEP REFINING ASSETS, L.P., a Delaware limited partnership

By: /s/ John Harrison__________________________

John Harrison

Vice President and Treasurer

S-5

HEP NAVAJO SOUTHERN, L.P., a Delaware limited partnership

By: HEP Pipeline GP, L.L.C., a Delaware limited liability company, its General Partner

By:/s/ John Harrison____________________

John Harrison

Vice President and Treasurer

S-6

U.S. BANK NATIONAL ASSOCIATION,
as Trustee

By:    /s/ Kristel D. Richards

Name:    Kristel D. Richards

Title:    Vice President

S-7

EX-10.1

FIRST AMENDMENT

TO

THIRD AMENDED AND RESTATED

MASTER THROUGHPUT AGREEMENT

This First Amendment to Third Amended and Restated Master Throughput Agreement (“this “Amendment”) is dated as of June 12, 2018, to be effective as of April 1, 2017 (the “Effective Time”) by and between HOLLYFRONTIER REFINING & MARKETING LLC (“HFRM”) and HOLLY ENERGY PARTNERS-OPERATING, L.P.(“HEP Operating”). Each of HFRM and HEP Operating are collectively referred to herein as the “Parties.”.

WHEREAS, the Parties desire to amend certain provisions of the Third Amended and Restated Master Throughput Agreement, effective as of January 1, 2017, by and between HFRM and HEP Operating (the “Agreement”) as set forth herein.

NOW, THEREFORE, in consideration of the covenants and obligations contained herein, the Parties hereby agree as follows:

ARTICLE 1

AMENDMENTS

1.1Amendment to Exhibit A.Exhibit A to the Agreement is hereby deleted and replaced in its entirety with Exhibit A attached to this Amendment.

1.2Amendment to Exhibit C.Exhibit C to the Agreement is hereby deleted and replaced in its entirety with Exhibit C attached to this Amendment.

1.3Amendment to Exhibit D. Exhibit D to the Agreement is hereby deleted and replaced in its entirety with Exhibit D attached to this Amendment.

1.4Amendment to Exhibit K. Exhibit K to the Agreement is hereby deleted and replaced in its entirety with Exhibit K attached to this Amendment.

1.5Amendment to Exhibit L-2. Exhibit L-2 to the Agreement is hereby deleted and replaced in its entirety with Exhibit L-2 attached to this Amendment.

ARTICLE 2MISCELLANEOUS

2.1Counterparts. This Amendment may be executed in counterparts each of which shall be deemed an original. An executed counterpart of this Amendment transmitted by facsimile shall be equally as effective as a manually executed counterpart.

2.2Successors and Assigns. Section 13.2 of the Agreement is hereby incorporated by reference into this Section 2.2, mutatis mutandis.

2.3Entire Agreement. The Agreement, as amended by this Amendment, contains the entire agreement between the Parties as to the subject matter of the Agreement and, except as provided for in this Amendment, the terms and provisions of the Agreement shall remain in full force and effectas originally written.

1

[Remainder of page intentionally left blank. Signature pages follow.]

IN WITNESS WHEREOF, the undersigned Parties have executed this Amendment as of the date first written above to be effective as of the Effective Time.

HEP OPERATING:

Holly Energy Partners-Operating, L.P.

By:     /s/ Richard L. Voliva III    

Richard L. Voliva III

Executive Vice President and CFO

HFRM:

HollyFrontier Refining & Marketing LLC

By:     /s/ Thomas G. Creery    

Thomas G. Creery

President

[Signature Page to the First Amendment to the Third Amended and Restated Master Throughput Agreement]

Exhibit A

to

Third Amended and Restated

Master Throughput Agreement

(as amended)

Definitions

“Actual Construction Costs” has the meaning set forth in Exhibit C.

“Actual OPEX” has the meaning set forth in Exhibit L-2.

“Affiliate” means, with to respect to a specified person, any other person controlling, controlled by or under common control with that first person. As used in this definition, the term “control” includes (i) with respect to any person having voting securities or the equivalent and elected directors, managers or persons performing similar functions, the ownership of or power to vote, directly or indirectly, voting securities or the equivalent representing 50% or more of the power to vote in the election of directors, managers or persons performing similar functions, (ii) ownership of 50% or more of the equity or equivalent interest in any person and (iii) the ability to direct the business and affairs of any person by acting as a general partner, manager or otherwise. Notwithstanding the foregoing, for purposes of this Agreement, HFRM, on the one hand, and HEP Operating, on the other hand, shall not be considered affiliates of each other.

“Agreement” has the meaning set forth in the preamble to this Agreement, as the same may be amended from time to time.

“API” means the American Petroleum Institute.

“API 653” means the Above Ground Storage Tank Inspector Program issued by the API as API Standard 653, as amended and supplemented from time to time.

“API Gravity” means the API index of specific gravity of a liquid petroleum expressed as degrees, as such index would be calculated on the date hereof.

“Applicable Asset” means each of the Cheyenne Assets, El Dorado Assets, Lovington Loading Rack, Malaga Pipeline System, Roadrunner Pipeline, Tulsa Assets, El Dorado Crude Tank Farm Assets, the Tulsa West Tankage and, solely with respect to Section 2.2, Section 2.14, Article 7 and Article 10 of this Agreement, the El Dorado Connector Pipeline, individually; and “Applicable Assets” means all of the foregoing assets, collectively.

“Applicable Law” means any applicable statute, law, regulation, ordinance, rule, judgment, rule of law, order, decree, permit, approval, concession, grant, franchise, license, agreement, requirement, or other governmental restriction or any similar form of decision of, or any provision or condition of any permit, license or other operating authorization issued under any of the foregoing by, or any determination of, any Governmental Authority having or asserting jurisdiction over the matter or matters in question, whether now or hereafter in effect and in each case as amended (including, without limitation, all of the terms and provisions of the common law of such Governmental Authority), as interpreted and enforced at the time in question.

“Applicable Tariff” means the Base Tariff and, to the extent applicable, the Incentive Tariff.

Exhibit A-1

“Applicable Term” has the meaning set forth in Article 7.

“ASTM” means ASTM International.

“Assumed OPEX” means, with respect to any Applicable Asset, the amount set forth on Exhibit C with respect to such Applicable Asset.

“Barrel” means 42 Gallons.

“Base Tariff” means the Base Tariff applicable to the quantity of Product transported, stored or loaded in connection with an Applicable Asset as set forth on Exhibit C, as such Base Tariff may be adjusted pursuant to the terms of this Agreement.

“bpd” means Barrels per day.

“Business Day” means any day other than Saturday, Sunday or other day upon which commercial banks in Dallas, Texas are authorized by law to close.

“Centurion Pipeline” means that certain 10” pipeline system operated by Centurion Pipeline L.P. and originating from Centurion’s Artesia Station located within Township 18S and Range 27E, approximately 1 mile south of HEP Operating’s Abo Station.

“Cheyenne Assets” means the Cheyenne Receiving Assets, Cheyenne Loading Rack and the Cheyenne Tankage.

“Cheyenne Loading Rack” means the refined products truck loading rack and the two (2) propane loading spots located at the Cheyenne Refinery and more specifically described in Exhibit I-1.

“Cheyenne Receiving Assets” means the pipelines set forth on Exhibit I-2.

“Cheyenne Refinery” means the refinery owned by HollyFrontier Cheyenne Refining LLC and located in Cheyenne, Wyoming.

“Cheyenne RCRA Order” means the administrative order set forth in Exhibit I.

“Cheyenne Tankage” means the tanks set forth on Exhibit I-3.

“Claim” means any existing or threatened future claim, demand, suit, action, investigation, proceeding, governmental action or cause of action of any kind or character (in each case, whether civil, criminal, investigative or administrative), known or unknown, under any theory, including those based on theories of contract, tort, statutory liability, strict liability, employer liability, premises liability, products liability, breach of warranty or malpractice.

“Closing Date” has the meaning for each Applicable Asset set forth in the Omnibus Agreement.

“Construction Projects” has the meaning set forth in Article 2.

“Contract Quarter” means a three-month period that commences on January 1, April 1, July 1 or October 1 and ends on March 31, June 30, September 30, or December 31, respectively.

Exhibit A-2

“Control” (including with correlative meaning, the term “controlled by”) means, as used with respect to any Person, the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Crude Agreement” means the Third Amended and Restated Crude Pipelines and Tankage Agreement, dated as of March 12, 2015, by and among HFRM, HEP Operating and certain other Affiliates of HFRM and HEP Operating.

“Crude Oil” means the direct liquid product of oil wells, oil processing plants, the indirect liquid petroleum products of oil or gas wells, oil sands or a mixture of such products, but does not include natural gas liquids, Refined Products, naphtha, gas oil, LEF (lube extraction feedstocks) or any other refined products.

“Deficiency Notice” has the meaning set forth in Section 10.1.

“Deficiency Payment” has the meaning set forth in Section 10.1.

“Devon” meansDevon Energy Production Company, L.P., and its Affiliates.

“Devon Lease Connections” has the meaning set forth in Exhibit G-3.

“DRA” has the meaning set forth in Section 2.6.

“Effective Time” means 12:01 a.m., Dallas, Texas time, on January 1, 2017.

“El Dorado Assets” means the El Dorado Loading Rack and the El Dorado Tankage.

“El Dorado Connector Pipeline” means that certain crude oil pipeline connecting the El Dorado Crude Tankage to the Pony Express Pipeline, which pipeline is owned by a Person that is not an Affiliate of either HFRM or HEP Operating.

“El Dorado Crude Tank Farm Assets” means the El Dorado Delivery Lines and the El Dorado Crude Tankage.

“El Dorado Crude Tank Farm Consideration Period” has the meaning set forth in Exhibit K.

“El Dorado Crude Tank Farm Quality Specifications” has the meaning set forth in Exhibit K.

“El Dorado Crude Tankage” means the tankage identified on Exhibit K-1.

“El Dorado Delivery Lines” has the meaning set forth in Exhibit K.

“El Dorado Loading Rack” means the Refined Products truck loading rack and the propane loading rack located at the El Dorado Refinery and more specifically described on Exhibit H-1.

“El Dorado Minimum Working Capacity” has the meaning set forth in Exhibit K.

“El Dorado Quality Specifications” means those specifications set forth in Exhibit K-2.

“El Dorado Refinery” means the refinery owned by HollyFrontier El Dorado Refining LLC and located in El Dorado, Kansas.

Exhibit A-3

“El Dorado Tankage” means the tanks set forth on Exhibit H-2.

“El Dorado Terminal” means the tank farm owned by HEP Operating and located in El Dorado, Kansas.

“Environmental Law” has the meaning set forth in the Omnibus Agreement.

“Excess Tariff Threshold” has the meaning set forth in Exhibit C.

“Exercise Notice” has the meaning set forth in Exhibit F.

“FERC Oil Pipeline Index” has the meaning set forth in Section 3(a)(iii)(B).

“Final Construction Cost” means the final aggregate construction cost of a New Tank, as contemplated by Exhibit H, Exhibit I and Exhibit J.

“Force Majeure” has the meaning set forth in the Omnibus Agreement.

“Force Majeure Notice” has the meaning set forth in the Omnibus Agreement.

“Gallon” means a United States gallon of two hundred thirty-one (231) cubic inches of liquid at sixty degrees (60°) Fahrenheit, and at the equivalent vapor pressure of the liquid.

“Governmental Authority” means any federal, state, local or foreign government or any provincial, departmental or other political subdivision thereof, or any entity, body or authority exercising executive, legislative, judicial, regulatory, administrative or other governmental functions or any court, department, commission, board, bureau, agency, instrumentality or administrative body of any of the foregoing.

“Heavy Products” means fuel oil, asphalt, coker feed, vacuum tower bottoms, atmospheric tower bottoms, pitch or roofing flux.

“HEP Operating” has the meaning set forth in the Preamble.

“HEP Operating Payment Obligations” has the meaning set forth in Section 15.1.

“HFRM” has the meaning set forth in the Preamble.

“HFRM Payment Obligations” has the meaning set forth in Section 14.1.

“High-API Surcharge” has the meaning set forth in Section 2.4.

“HollyFrontier” means HollyFrontier Corporation, a Delaware corporation.

“HollyFrontier Navajo” means HollyFrontier Navajo Refining LLC.

“HollyFrontier Tulsa” means HollyFrontier Tulsa Refining LLC.

“Incentive Tariff” means the Incentive Tariff applicable to the quantity of Product transported, stored or loaded in connection with an Applicable Asset as set forth on Exhibit C, as such Incentive Tariff may be adjusted pursuant to the terms of this Agreement.

Exhibit A-4

“Intermediate Products” means non-finished intermediate products, including high sulfur diesel fuel for DHT feed, jet fuel, naphtha for reformer feed, gas oil or LEF for FCC feed, reformate, light straight run, hydrogen, fuel gas and sour fuel gas.

“Jayhawk” means Jayhawk Pipeline, L.L.C. (or its successors to the Jayhawk Tankage).

“Jayhawk Lease” means the lease between HEP-Operating and Jayhawk for the Jayhawk Tankage in existence as of the commencement of the Applicable Term.

“Jayhawk Tankage” means the tankage identified in Exhibit K-1.

“Lovington Loading Rack” means that certain asphalt loading rack located at the Navajo Refinery.

“LPG Products” means propane, refinery grade propylene, normal butane and isobutane.

“Malaga Capacity Estimate” has the meaning set forth in Exhibit G.

“Malaga Commencement Date” means the date on which, in the reasonable opinion of HEP Operating, the Malaga Pipeline System is available for service and operating as expected in delivering Crude Oil, which date has been specified in written notice from HEP Operating to HFRM at least 60 days prior to the Malaga Commencement Date; provided, however, that if the Malaga Pipeline System is, in the discretion of HEP Operating, substantially complete, then the parties may agree in writing to a commencement date prior to the Malaga Pipeline System being fully completed.

“Malaga Construction Projects” has the meaning set forth in Exhibit G.

“Malaga Exercise Notice” has the meaning set forth in Exhibit G.

“Malaga Initial Period” means the period beginning on the Malaga Commencement Date through and including final day of the 20^th full Contract Quarter following the Malaga Commencement Date.

“Malaga Pipeline System” means the pipeline systems (a) extending from the (i) Whites City Road Station to the HEP Operating Artesia Station, from (ii) Devon Parkway field to the Millman Station and the HEP Operating Artesia Station, (iii) HEP Operating Artesia Station to the Beeson Station, (iv) the Beeson Station to the Anderson Ranch Pipeline, (v) Devon Hackberry field to the Beeson Station, and (v) Beeson Station to the Plains Pipeline, including in each case all related lease connection pipelines, storage facilities, crude oil gathering tanks, and truck off-loading facilities, as depicted on Exhibit G-1 (Map of Pipeline System and Pipeline System Capacity by Segment), and (b) with the volume capacities as set forth on Exhibit G-1, described on Exhibit G-2 (Construction Projects) and described on Exhibit G-3 (Devon Lease Connections).

“Master Lease and Access Agreement” means that certain Fourth Amended and Restated Master Lease and Access Agreement dated January 18, 2017 among certain of the Affiliates of HEP Operating and the owners of the Refineries, as the same may be amended from time to time.

“Minimum Capacity Commitment” has the meaning set forth in Section 2.2(a).

“Minimum Revenue Commitment” has the meaning set forth in Section 2.2(a).

Exhibit A-5

“Minimum Throughput Commitment” means the quantity of Product to be transported, stored or loaded in connection with an Applicable Asset, as set forth on Exhibit C, as such amount may be adjusted pursuant to the terms of this Agreement.

“MSCFD” means thousands of cubic feet per day.

“MVP Pipeline” has the meaning set forth in Exhibit K.

“Navajo Refinery” means the refinery owned by HollyFrontier Navajo and located in Lovington, New Mexico.

“New Tank” means the new petroleum products storage tankage to be added to the Applicable Assets as identified on Exhibits H and J.

“New Tank Commencement Date” means, with respect to each New Tank, the first day of the calendar month after the date on which, in the reasonable opinion of HEP Operating, such New Tank is mechanically complete, available for service and operating as expected in storing the Product for which such New Tank was designed, which date has been specified in written notice from HEP Operating to HFRM at least 30 days prior to such date.

“Omnibus Agreement” means the Eighteenth Amended and Restated Omnibus Agreement dated January 19, 2018, as the same may be amended from time to time.

“OPEX Reimbursement Amount” has the meaning set forth in Exhibit L-2.

“Original Master Throughput Agreement” has the meaning set forth in the Recitals.

“Osage Pipeline” has the meaning set forth in Exhibit K.

“Parties” has the meaning set forth in the Preamble.

“Partnership” means Holly Energy Partners, L.P., a Delaware limited partnership.

“Party” has the meaning set forth in the Preamble.

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Pipelines” means the Malaga Pipeline System, Roadrunner Pipeline, the Tulsa Pipelines, the Tulsa Interconnecting Pipelines, and the El Dorado Delivery Lines, and any other pipeline included in the Applicable Assets.

“Plains Pipeline” means that certain 16” diameter pipeline operated by Plains All American Pipeline, L. P. and located in Lea County, New Mexico and which crosses the HEP Anderson Ranch gathering system in Township 18 South, Range 32 East.

“Pony Express Pipeline” has the meaning set forth in Exhibit K.

Exhibit A-6

“Previous Amended and Restated Master Throughput Agreement” has the meaning set forth in the Recitals.

“Prime Rate” means the prime rate per annum announced by Union Bank, N.A., or if Union Bank, N.A. no longer announces a prime rate for any reason, the prime rate per annum announced by the largest U.S. bank measured by deposits from time to time as its base rate on corporate loans, automatically fluctuating upward or downward with each announcement of such prime rate.

“Prior Agreements” means those agreements set forth in Recitals A through F. For the avoidance of doubt, “Prior Agreements” do not include the following agreements (as amended, modified or supplemented and in effect from time to time): (a) Amended and Restated Intermediate Pipelines Agreement dated June 1, 2009, (b) Tulsa Equipment and Throughput Agreement dated August 1, 2009, (c) Amended and Restated Refined Product Pipelines and Terminals Agreement effective February 1, 2009, (d) Second Amended and Restated Throughput Agreement effective June 1, 2013, (e) Third Amended and Restated Crude Pipelines and Tankage Agreement dated March 12, 2015, and (f) Unloading and Blending Services Agreement (Artesia) dated March 12, 2015.

“Products” has the meaning set forth in Exhibit C.

“Qualified Third-Party Throughput” has the meaning set forth in Exhibit C.

“Red Rock Pipeline” has the meaning set forth in Exhibit K.

“Refined Products” means gasoline, kerosene, ethanol and diesel fuel.

“Refineries” means the Navajo Refinery; the El Dorado Refinery; the Cheyenne Refinery; the Tulsa East Refinery and the Tulsa West Refinery.

“Roadrunner Pipeline” means that certain 16” crude oil pipeline extending approximately 65 miles from the Slaughter station to Lovington, New Mexico.

“Subsequent Year” has the meaning set forth in Exhibit G.

“Subsidiary” means with respect to any Person (the “Owner”), any corporation or other Person of which securities or other interests having the power to elect a majority of that corporation’s or other Person’s board of directors or similar governing body, or otherwise having the power to direct the business and policies of that corporation or other Person (other than securities or other interest having such power only upon the happening of a contingency that has not occurred), are held by the Owner or one or more of its Subsidiaries.

“Surcharge Tariff” has the meaning set forth in Exhibit C.

“SUS” means Saybolt Universal Seconds as specified by ASTM Standard D2161-10, as amended, supplemented or replaced from time to time.

“Tulsa Assets” means the Tulsa Group 1 Tankage, Tulsa Group 1 Loading Rack, Tulsa Group 1 Pipeline, Tulsa Group 2 Tankage, Tulsa Group 2 Loading Rack and the Tulsa Interconnecting Pipelines.

“Tulsa East Refinery” means the refinery owned by HollyFrontier Tulsa and located at 905 West 25^th Street, Tulsa, Oklahoma 74107.

Exhibit A-7

“Tulsa Group 1 Purchase Agreement” means that certain Asset Sale and Purchase Agreement dated as of October 1, 2009 by and among HollyFrontier Tulsa, HEP Tulsa LLC and Holly Energy Storage – Tulsa.

“Tulsa Group 1 Loading Rack” means the gas oil, asphalt and propane truck loading racks located at the Tulsa West Refinery and more specifically described in Exhibit J-1 attached hereto.

“Tulsa Group 1 Tankage” means the tankage identified in Exhibit J-3 attached hereto.

“Tulsa Group 2 Purchase Agreement” means that certain LLC Interest Purchase Agreement dated as of March 31, 2010 by and between HEP Tulsa LLC, Lea Refining Company, and HollyFrontier Tulsa.

“Tulsa Group 2 Tankage” means the tankage identified in Exhibit J-5.

“Tulsa Group 2 Loading Rack” means the rail loading rack located at the Tulsa West Refinery and more specifically described in Exhibit J-4.

“Tulsa Interconnecting Pipelines” means the following pipelines between the Tulsa East Refinery and the Tulsa West Refinery: 1) the 12 inch raw gas oil/diesel line (the “Distillate Interconnecting Pipeline”), 2) the 12 inch naphtha/gasoline component line (the “Gasoline Interconnecting Pipeline”), 3) the 12 inch refinery fuel gas line (the “Refinery Fuel Gas Interconnecting Pipeline”), 4) the 8 inch hydrogen line (the “Hydrogen Interconnecting Pipeline”), and 5) the 10 inch refinery sour fuel gas line (the “Refinery Sour Fuel Gas Interconnecting Pipeline”) including delivery facilities from the Tulsa West Refinery and receipt facilities at the Tulsa East Refinery for the Distillate and Gasoline Interconnecting Pipelines, but not for the Refinery Fuel Gas, Hydrogen, and Refinery Sour Fuel Gas Interconnecting Pipelines.

“Tulsa Group 1 Pipeline” means those two (2) product delivery lines extending from the Group 1 Tankage to interconnection points with the Magellan pipeline as more specifically described in Exhibit J-2 attached hereto.

“Tulsa Purchase Agreements” means the Tulsa Group 1 Purchase Agreement and the Tulsa Group 2 Purchase Agreement.

“Tulsa West Refinery” means the refinery owned by HollyFrontier Tulsa located at 1700 S. Union, Tulsa, Oklahoma.

“Tulsa West Tankage” means the tankage identified in Exhibit L-1.

“Working Capacity” has the meaning set forth in Exhibit K.

Exhibit A-8

Exhibit C

to

Third Amended and Restated

Master Throughput Agreement

(as amended)

Applicable Assets, Product, Minimum Capacity Commitment, Tariffs, Tariff Adjustments and Applicable Terms*

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

Malaga Pipeline System

Pipelines

Crude Oil

40,000 bpd 1

40,000 bpd2

$0.5334/bbl2

40,000 bpd2

$0.3137/bbl

—

FERC Adjustment

—

July 1, 2015

—

12:01 a.m. on June 1, 2013 to Sept. 1, 2024 (the “Malaga Commencement Date”)

Exhibit C-1

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

El Dorado Assets

Pipelines

Refined Products LPG Products, Intermediate Products Heavy Products

120,000 bpd of aggregate delivery capacity from the Tankage

120,000 bpd of Intermediate and Refined Product

$0.1625/bbl

125,000 bpd of Intermediate and Refined Product

$0.01/bbl

—

PPI Adjustment

3% in any calendar year (applicable to each individual tariff)

July 1, 2012

—

12:01 a.m. on Nov. 1, 2011 to 12:01 a.m. on Oct. 31, 2026; provided that with respect to the New Tank at the El Dorado Refinery, the Applicable Term shall be from 12:01 a.m. on the New Tank Commencement Date for such New Tank to the date occurring fifteen (15) years thereafter.

Tankage

140,000 bpd of aggregate capacity in the Tankage

140,000 bpd of Products

$0.4784 /bbl3,4

154,000 bpd of Products

$0.2167/bbl

—

Loading Rack

20,000 bpd

20,000 bpd

$0.2708/bbl

—

—

—

Exhibit C-2

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

Cheyenne Assets

Cheyenne Receiving Assets

Crude Oil

41,000 bpd

46,000 bpd

$0.3251/bbl

50,600 bpd

$0.1517/bbl

—

PPI Adjustment

3% in any calendar year (applicable to each individual tariff)4

July 1, 2012

—

12:01 a.m. on Nov. 1, 2011 to 12:01 a.m. on Oct. 31, 2026; provided that with respect to (a) Cheyenne New Tank No. 117, the Applicable Term shall be from 12:01 a.m. on December 4, 2014 to 12:01 a.m. on December 4, 2029, and (b) any New Tanks at the Cheyenne Refinery, the Applicable Term is 12:01 a.m. on the New Tank Commencement Date for each such New Tank to the date occurring fifteen (15) years thereafter.

Cheyenne Tankage

46,000 bpd

41,000 bpd

$0.4673/bbl3,5

45,100 bpd

$0.2167/bbl

—

Cheyenne Loading Rack

41,000 bpd

$0.2708/bbl

None

—

—

Exhibit C-3

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

Tulsa East Assets

Tulsa Pipelines

Refined Products

60,000 bpd

60,000 bpd

$0.1116/bbl

—

—

PPI Adjustment

3% in any calendar year (applicable to each individual tariff)

July 1, 2011

—

11:59 p.m. on Mar. 31, 2010 to 12:01 a.m. on Dec. 1, 2024

Tulsa Group 1 Tankage

Various

1,362,550 bbls

80,000 bpd

$0.3960/bbl

Each throughput barrel over the Minimum Throughput Commitment but less than or equal to the Excess Tariff Threshold

$0.1116/bbl

$0.2455/bbl (over 120,000 bpd of Refined Products, in the aggregate on average for each Contract Quarter)

Tulsa Group 1 Loading Rack

Various

26,000 bpd

26,000 bpd

$0.3348/bbl

—

—

—

Exhibit C-4

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

Tulsa Group 2 Tankage

Various

2,122,644 bbl

90,000 bpd

$0.4605/bbl

Each throughput barrel over the Minimum Throughput Commitment but less than or equal to the Excess Tariff Threshold

$0.1116/bbl

$0.2455/bbl (over 120,000 bpd of Refined Products, in the aggregate on average for each Contract Quarter)

Tulsa Group 2 Loading Rack

1,800 bpd

1,800 bpd

$0.3906/bbl

—

—

—

Tulsa Inter-connecting Pipelines6

Distillate Interconnect-ing Pipeline – 45,000 bpd (maximum)

45,000 bpd

$0.2267/bbl (to 45,000 bpd in the aggregate, on average for each Contract Quarter)

Over 45,000 bpd and less than or equal to 65,000 bpd

$0.0758/bbl

$0.0541/bbl (over 65,000 bpd of Refined Products, in the aggregate on average for each Contract Quarter)

Exhibit C-5

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

Gasoline Interconnect-ing Pipeline – 45,000 bpd (maximum)

45,000 bpd of Intermediate Products shipped between the Tulsa East Refinery and the Tulsa West Refinery via the Interconnecting Pipelines (excluding the Distillate Interconnecting Pipeline and the Tulsa Pipelines

Hydrogen Interconnect-ing Pipeline –10,000 MSCFD of hydrogen (maximum)

64,000 MSCFD

$0.0693/ MSCF/day

—

—

—

Refinery Fuel Gas Interconnect-ing Pipeline – 32,000 MSCFD of refinery fuel gas (maximum)

Exhibit C-6

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

Refinery Sour Fuel Gas Interconnecting Pipeline – 22,000 MSCFD of refinery sour fuel gas (maximum)

Lovington Assets

Lovington Loading Rack

Asphalt and any other petroleum or petroleum based or derived products

4,000 bpd

4,000 bpd

$0.3906/bbl

—

—

PPI Adjustment4

3% in any calendar year

July 1, 2011

—

11:59 p.m. on Mar. 31, 2010 to 12:01 a.m. on Mar. 31, 2025

Roadrunner Assets

Pipelines

Crude Oil

40,000 bpd

40,000 bpd7

$0.7174/bbl

Each throughput barrel over the Minimum Throughput Commitment

$0.3757/bbl 8

—

PPI Adjustment

3% plus ½ of the PPI increase in excess of 3% for such calendar year.

July 1, 2011

—

12:01 a.m. on Dec. 1, 2009 to 12:01 a.m. on Dec. 1, 2024

Exhibit C-7

Applicable Assets

Type of Applicable Asset

Product

Minimum Capacity Commitment (aggregate capacity unless otherwise noted)

Minimum Throughput Commitment (in the aggregate, on average, for each Contract Quarter)

Base Tariff (applicable to all movements below the Incentive Tariff Threshold)

Incentive Tariff Threshold (in the aggregate, on average, for each Contract Quarter)

Incentive Tariff (applicable to all movements at or above the Incentive Tariff Threshold)

Excess Tariff (applicable to all movements above the Excess Tariff Thresholds set forth below, if any)

Tariff Adjustment

Tariff Adjustment Minimum/Cap

Tariff Adjustment Commencement Date

Assumed OPEX

Applicable Term (all times are Dallas, TX time)

El Dorado Crude Tankage

Tankage

Crude Oil; Intermediate Products

140,000 bpd

140,000 bpd

$0.0958/bbl

Each throughput barrel over the Minimum Throughput Commitment

$0.0101/bbl

—

PPI Adjustment

Subject to 1% minimum / 3% cap 9

July 1, 2016

—

12:01 a.m. on March 6, 2015 to 12:01 a.m. on March 6, 2025

El Dorado Connector Pipeline 10

Pipelines

Crude Oil: Intermediate Products

—

—

$0.0800/bbl

—

—

—

PPI Adjustment

Subject to 1% minimum / 3% cap 9

July 1, 2019

—

12:01 a.m. on January 1, 2018 to 12:01 a.m. on March 6, 2025.

Tulsa West Tankage

Tankage

Crude/Lef

396,000 bpd

80,000 bpd

$0.2143/bbl11

—

—

—

PPI Adjustment

Subject to 1% minimum / 3% cap9

July 1, 2017

$2,751,331

12:01 a.m. on March 31, 2016 to 12:01 a.m. on March 31, 2026

* Tariffs listed on this Exhibit are effective as of July 1, 2016, other than: (1) the Base Tariff with respect to the El Dorado Assets - Tankage, which is effective as of January 1, 2017; (2) the Base Tariff with respect to the Tulsa West Tankage, which is effective as of April 1, 2017; and (3) the Base Tariffs with

respect to the El Dorado Crude Tankage and the El Dorado Connector Pipeline, which are effective as of January 1, 2018.

^1. As may be adjusted pursuant to Exhibit G.

Exhibit C-8

² During the first five years of the Applicable Term, following the Malaga Commencement Date, HFRM shall pay HEP Operating an extra surcharge per barrel (the “Surcharge Tariff”). The Surcharge Tariff for each Contract Quarter is equal to:

Actual Construction Costs - $38,500,000

Minimum Pipeline Throughput x 365 x 5

where “Actual Construction Costs” means the actual, reasonable and necessary costs, or as otherwise approved in writing by HFRM, incurred by HEP Operating to construct the Malaga Construction Projects and the Devon Lease Connections; provided, however, that the numerator of the formula for calculating the Surcharge Tariff (Actual Construction Costs - $38,500,000) shall not exceed $13,500,000 such that the maximum value for such numerator shall be $13,500,000. At the end of each Contract Quarter during the first five years of the Applicable Term, following the Malaga Commencement Date, HFRM shall pay HEP Operating an amount for each Contract Quarter determined by multiplying the Minimum Throughput Commitment for the Malaga Pipeline System for such Contract Quarter, by the Surcharge Tariff. The Surcharge Tariff is in addition to the Applicable Tariff to be paid by HFRM.

³From and after the New Tank Commencement Date established pursuant to Exhibit H, if any, the Tankage Base Tariff shall be increased by an amount per barrel equal to:

Final Construction Cost

0.9 x 8.1928 x Minimum Tankage Throughput x 365

For example, if the Final Construction Costs = $1,500,000, the per barrel increase in the Tankage Base Tariff would be calculated as follows:

$1,500,000/(0.9 x 8.1928 x 140,000 x 365) = $0.0040.

⁴ Reflects reduction in throughput fee effective January 1, 2015 as a result of the secondment arrangement at the El Dorado refinery. Also reflects reduction in throughput fee effective January 1, 2017 as a result of the sale of tanks 243 and 244 from El Dorado Logistics LLC to HollyFrontier El Dorado Refining LLC.

⁵ Reflects reduction in throughput fee effective January 1, 2015 as a result of the secondment arrangement at the Cheyenne refinery.

⁶The Minimum Interconnecting Pipeline Revenue Commitment shall be an amount of revenue to HEP Operating for each Contract Quarter determined by adding: 1) the Minimum Interconnecting Pipeline Liquid Throughput multiplied by the Interconnecting Pipeline Liquid Tariff, and 2) the Minimum Interconnecting Pipeline Gas Throughput multiplied by the Interconnecting Pipeline Gas Tariff.

⁷In the event that any third party transports Crude Oil on the Roadrunner Pipeline for ultimate delivery to HollyFrontier or any of its Subsidiaries and such third party pays throughput fees equal to or greater than the then-current base tariff for each such barrel of Crude Oil transported on the Roadrunner Pipeline for ultimate delivery to HollyFrontier or any of its Subsidiaries (“Qualified Third-Party Throughput”), then revenues paid to HEP Operating by such third party for such Qualified Third-Party Throughput shall be credited towards the Minimum Revenue Commitment hereunder for the Roadrunner Pipeline.

⁸If the average throughput for any Contract Quarter (including Qualified Third-Party Throughput) exceeds the Minimum Pipeline Throughput attributable to such Contract Quarter, then for each throughput barrel in excess of the Minimum Pipeline Throughput, HFRM shall pay HEP Operating throughput fees in the amount of the Pipeline Incentive Tariff.

⁹For the avoidance of doubt, if the change in PPI in any year is less than one percent (1%) it will be rounded up to one percent (1%) and if the change in PPI in any year is greater than three percent (3%) it will be rounded down to three percent (3%).

¹⁰See the definition of “Applicable Asset” in this Agreement.

¹¹The Base Tariff from March 31, 2016 to March 31, 2017 was $0.218/bbl. The Base Tariff of $0.2143/bbl is effective as of April 1, 2017.

Exhibit C-9

Applicable Tariff Adjustments

FERC Adjustment:

Each Applicable Tariff shall be adjusted on July 1 of each index year during the Applicable Term by an amount equal to the percentage change, if any, between the two (2) immediately preceding index years, in the Federal Energy Regulation Commission Oil Pipeline Index (the “FERC Oil Pipeline Index”); provided, however, that if the percentage change, if any, between the two (2) immediately preceding index years in the FERC Oil Pipeline Index is negative, then there will be no change to the Applicable Tariffs.

PPI Adjustment:

Each Applicable Tariff shall be adjusted on July 1 of each calendar year by an amount equal to the upper change in the annual change rounded to four decimal places of the Producers Price Index-Commodities-Finished Goods, (PPI), et al. (“PPI”), produced by the U.S. Department of Labor, Bureaus of Labor Statistics. The series ID is WPUFD49207 as of June 1, 2016 – located at http://www.bls.gov/data/. The change factor shall be calculated as follows: annual PPI index (most current year) less annual PPI index (most current year minus 1) divided by annual PPI index (most current year minus 1). An example for year 2014 change is: [PPI (2013) – PPI (2012)] / PPI (2012) or (197.3 – 193.3) / 193.3 or .021 or 2.1%. If the PPI index change is negative in a given year then there will be no change in the tariff unless the tariff is subject to a minimum increase as defined elsewhere in Exhibit C.

Index no longer Published

If the either index is no longer published, the Parties shall negotiate in good faith to agree on a new index (as applicable) that gives comparable protection against inflation or deflation, and the same method of adjustment for increases or decreases in the new index shall be used to calculate increases or decreases in the tariffs. If the Parties are unable to agree, a new index will be determined in accordance with the dispute resolution provisions set forth in the Omnibus Agreement, and the same method of adjustment for increases or decreases in the new index shall be used to calculate increases or decreases in the tariffs.

Exhibit C-8

Exhibit D

to

Third Amended and Restated

Master Throughput Agreement

(as amended)

Measurement of Shipped Volumes

Exhibit D-1

Applicable Asset	Type of Applicable Asset	Measurement of Volumes
Malaga Pipeline System	Pipelines	Quantities shipped on the Malaga Pipeline System shall be determined by measuring unique barrels of Crude Oil (either by counting barrels or calculating barrels based on available meter data) shipped on the following origin and destination pairings: Whites City Road Station to HEP Artesia Station Whites City Road Station to Beeson Station Whites City Road Station to Plains Pipeline Bisti Connection HEP Artesia Station to Beeson Station HEP Artesia Station to Plains Pipeline Bisti Connection Beeson Station to Plains Pipeline Bisti Connection The origin and destination pairings listed above utilize the following segments of the Pipeline System: Whites City Road Station to HEP Artesia Station (8-inch) HEP Artesia Station to Beeson Station (8-inch) Beeson Station to Plains Pipeline Bisti Connection (12-inch) Shipments on any other segments of the Malaga Pipeline System will be charged the then-current tariff and fees under the Crude Agreement. For the avoidance of doubt, a barrel shipped on multiple segments of the Malaga Pipeline System shall only be counted as one barrel in satisfaction of the Minimum Throughput Commitment and shall not count as a separate barrel on each such segment. For example, a barrel shipped from Whites City Road Station to the Plains Pipeline Bisti Connection shall count as one barrel in satisfaction of the Minimum Throughput Commitment, and not as three barrels since it flows on three segments of the Malaga Pipeline System.
El Dorado Assets	Pipelines	Pipeline delivery throughput shall be determined by the shipments of Products by pipeline (and not over the Loading Racks) from the El Dorado Refinery.
	Tankage	Tankage throughput shall be determined by the sum of Products shipped from the El Dorado Refinery but not including shipments of coke and sulfur. For the avoidance of doubt, no Tankage throughput fees shall be paid for movements of Products within the El Dorado Refinery.
	Loading Rack	The Loading Rack Tariff will be paid for all quantities of Products or other materials loaded at the Loading Racks or the asphalt loading rack and any Products or other materials shipped using the weight scales.
Cheyenne Assets	Cheyenne Receiving Assets	Crude Oil throughput shall be determined by the total shipments of Crude Oil by pipeline, truck and rail received at the Cheyenne Refinery.
	Cheyenne Tankage	Tankage throughput shall be determined by the sum of Products shipped by the Refinery but not including shipments of coke and sulfur. For the avoidance of doubt, no Tankage throughput fees shall be paid for movements of Products within the Cheyenne Refinery.
	Cheyenne Loading Rack	The Applicable Tariff for the Loading Rack will be paid for (A) all quantities of Products shipped out of the Cheyenne Refinery by pipeline or asphalt loading racks, and (B) all quantities of Products, Crude Oil and any other materials (such as coke and sulfur) loaded at the Loading Racks or the weight scales.
Tulsa East Assets	Pipelines	Pipeline throughput will be determined by the quantities of Refined Product shipped on the Tulsa Pipelines.

Exhibit D-2

	Group 1 Tankage	Group 1 Tankage throughput shall be determined by the sum of Refined Products shipped on the Pipelines and loaded at the Group 1 Loading Rack. Any streams moved internally within the Tulsa East Refinery will not be included in determining the volumes for any Minimum Revenue Commitment for the Group 1 Tankage. 1
	Group 1 Loading Rack	The Group 1 Loading Rack Tariff will be paid for all quantities of Products loaded at the Group 1 Loading Rack.
	Group 2 Tankage	Group 2 Tankage throughput shall be determined by the sum of pipeline quantities of Crude Oil and Intermediate Products received at the Tulsa East Refinery, including Crude Oil and Intermediate Products received at the Tulsa East Refinery from the Tulsa West Refinery. Any streams moved internally within the Tulsa East Refinery will not be included in determining the volumes for any Minimum Revenue Commitment for the Group 2 Tankage. Any Refined Products received from the Tulsa West Refinery or moved out of the Tulsa East Refinery will not be included in determining the volumes for the Minimum Revenue Commitment for the Group 2 Tankage.1
	Group 2 Loading Rack	The Group 2 Loading Rack Tariff will be paid for all quantities of Products loaded at the Group 2 Loading Rack.
	Interconnecting Pipelines	The Interconnecting Pipeline Gas Throughput shall be determined by the sum of pipeline quantities of Intermediate Products shipped between the Tulsa East Refinery and the Tulsa West Refinery via the Hydrogen Interconnecting Pipeline, Refinery Fuel Gas Interconnecting Pipeline, and Refinery Sour Fuel Gas Interconnecting Pipeline. The Interconnecting Pipeline Liquid Throughput shall be determined by the sum of pipeline quantities of Intermediate Products shipped between the Tulsa East Refinery and the Tulsa West Refinery via the Gasoline Interconnecting Pipeline and Distillate Interconnecting Pipeline.
Lovington Assets	Loading Rack	The Loading Rack Tariff will be paid for all quantities of Products loaded at the Lovington Loading Rack.
Roadrunner Assets	N/A	N/A
El Dorado Crude Tankage	Tankage	El Dorado Tankage throughput shall be determined by the sum of the pipeline quantities of Product received at the El Dorado Crude Tankage, based on custody transfer meters. For avoidance of doubt, no throughput fees shall be paid for movements of Products among the El Dorado Crude Tankage.
El Dorado Connector Pipeline 2	Pipelines	El Dorado Connector Pipeline throughput shall be determined by the sum of the pipeline quantities of Product shipped from the Pony Express Pipeline to the El Dorado Crude Tankage via the El Dorado Connector Pipeline, based on measurement tickets from the meter owned by the Pony Express Pipeline and located upstream of the custody transfer flange.
Tulsa West Tankage	Tankage	Tulsa West Tankage throughput shall be determined by barrels of crude/lef deliveries at the following meters at the Tulsa West Refinery: #1387, #175, #176, #177, #178, #179, #180, #334, #1373 and #809.

¹For the avoidance of doubt, any high sulfur diesel fuel that HFRM may transport from the Tulsa West Refinery through the Group 1 Tankage or Group 2 Tankage for processing in the Tulsa East Refinery’s distillate hydrotreater shall be subject to the Group 2 Tankage Applicable Tariffs, and the resulting ultra low sulfur diesel fuel produced from the high sulfur diesel fuel and then shipped from the Tulsa East Refinery via either the Tulsa Pipelines or the loading rack located at the Tulsa East Refinery shall be subject to the applicable Group 1 Tankage Applicable Tariffs.

²See the definition of “Applicable Asset” in this Agreement.

Exhibit D-2

Exhibit K

to

Third Amended and Restated

Master Throughput Agreement

(as amended)

Special Provisions: El Dorado Crude Tank Farm Assets

1. El Dorado Terminal Operation. HEP Operating will use commercially reasonable efforts to maintain the El Dorado Terminal’s current connections to the pipelines owned and operated by (a) Tallgrass Energy Partners, LP (the “Pony Express Pipeline”), (b) Osage Pipe Line Company, LLC (the “Osage Pipeline”), (c) Rose Rock Midstream, L.P. (the “Rose Rock Pipeline”), and (d) MV Purchasing, LLC (the “MVP Pipeline”), but shall not be required to expend additional monies in connection therewith unless agreed separately in writing with HFRM. HFRM may request HEP Operating to connect the El Dorado Crude Tankage to new pipelines, whether owned by third parties or by HFRM, subject to HEP Operating’s approval of such connections and the engineering standards related to such; HEP Operating will not unreasonably withhold such approval. If HEP Operating approves any new connection requested by HFRM, HFRM will reimburse HEP Operating the actual expenses incurred by HEP Operating that are associated with such connection, plus an administrative charge of fifteen percent (15%). In addition, the Minimum Throughput Commitment will be increased to account for any additional expense HEP Operating bears in connection with ongoing operating expenses associated with such requested pipeline connection. Any HEP Operating expenditures requested by HFRM beyond pipeline connections will be negotiated separately.

2. Tank Use. HEP Operating shall make available to HFRM on an exclusive basis the shell capacity, minimum and maximum capacities, and working capacity for the El Dorado Crude Tankage. HEP Operating will make at least two (2) of such tanks available for blending services at all times during the Applicable Term. HEP Operating and HFRM will work together to assign minimum and maximum capacities of each tank within sixty (60) days following the commencement of the Applicable Term. These minimum and maximum capacities will be set to allow the most working capacity available to HFRM within reasonable industry practices. The minimum and maximum capacity for each tank will be used to determine the working capacity of each tank (calculated by subtracting the minimum capacity from the maximum capacity for each Tank) (the “Working Capacity”). Once the Working Capacity is agreed upon, HEP may assign, in its sole discretion, new maximum and minimum capacities to each tank if required to allow for safe operation. If HEP determines it is necessary to reduce the aggregate Working Capacity to less than 650,000 Barrels (as such volume may be adjusted pursuant to Section 4 of this Exhibit K (the “El Dorado Minimum Working Capacity”), the Minimum Throughput Commitment will be reduced proportionately. HFRM may deliver or have delivered Product into the El Dorado Crude Tankage from the El Dorado Refinery, the Pony Express Pipeline, the Osage Pipeline the Rose Rock Pipeline or the MVP Pipeline. HFRM agrees not to deliver to the Terminal any Products which fail to meet the El Dorado Quality Specifications, or which would in any way be injurious to the El Dorado Crude Tankage, or that may not lawfully be handled in the Tankage. HFRM shall be responsible for and pay for all damages resulting from handling of any Products by HFRM, its designee, or its consignee; provided, however, so long as the Products meet the El Dorado Quality Specifications, HFRM shall not be responsible

Exhibit K-1

for damages arising from the negligence or willful misconduct of HEP, its agents, employees or contractors or from ordinary wear and tear.

3. Terminal Maintenance, Changes, or Installations. HEP Operating shall make the El Dorado Crude Tankage available for HFRM’s exclusive use except for times at which a tank must be taken out of service for routine maintenance, in which event HEP Operating will use commercially reasonable efforts to minimize the duration of the outage. HEP Operating may take more than one tank out of service due to unplanned maintenance, environmental, or operational occurrences and may schedule more than one tank out of service if the duration is minimal (i.e. less than 1 week for seal inspection or mixer repair on top of an API 653 of another tank), but HEP Operating will not schedule more than one tank out of service for extended overlapping periods (e.g., two API 653s at the same time overlapping 1+ weeks). HEP Operating will provide HFRM written notice at least forty-five (45) days prior to any scheduled maintenance, changes or installations affecting the El Dorado Crude Tankage. In the event HEP Operating cannot provide any or all of the services during any maintenance, changes or installations within the El Dorado Terminal, or if such maintenance, changes or installations causes HEP Operating to take any tank out of service and HEP Operating does not provide a substitute tank in the place of such tank, the Minimum Throughput Commitment shall be reduced by the Working Capacity of such out-of-service tank for the duration of such outage.

4. Right of First Refusal. HEP Operating may not lease or pledge or commit to provide any storage services with respect to the El Dorado Crude Tankage or the Jayhawk Tankage (after the expiration of the Jayhawk Lease) at the El Dorado Terminal to a third party unless HEP Operating first offers to HFRM the exclusive right to use the Working Capacity of such tanks on substantially the same terms as HEP Operating has previously negotiated with a third party in arms-length negotiations. HFRM will have thirty (30) days (the “El Dorado Crude Tank Farm Consideration Period”) to consider the option to utilize such Working Capacity and to provide notice to HEP Operating of its election to accept or decline such Working Capacity. If HFRM has not notified HEP Operating within 30 days, then HEP Operating may proceed to enter into an agreement with the third party for such Working Capacity; provided, however, that if HEP Operating does not enter into an agreement with the third party within sixty (60) days following HFRM’s notice to decline or the expiration of the El Dorado Crude Tank Farm Consideration Period, then HFRM’s rights under this Section 4 will apply to any subsequent bona fide third party offer to HEP Operating regarding such Working Capacity.

5. Jayhawk Tankage. In the event that the Jayhawk Lease expires or is otherwise terminated or cancelled for any reason and the Jayhawk Tankage are not leased within a reasonable time (not to exceed sixty 60) days) to a third party as contemplated by Section 4 of this Exhibit K, HEP Operating agrees to make the Working Capacity of the Jayhawk Tankage available for HFRM’s exclusive use, and HFRM agrees to increase the Minimum Throughput Commitment by an amount equal to (a) the monthly storage fee that Jayhawk paid to HEP Operating during the last 12 months of the Jayhawk Lease, divided by the Working Capacity of the Jayhawk Tankage, and the El Dorado Minimum Working Capacity shall be increased by an amount equal to two-thirds (2/3) of the Working Capacity of such Jayhawk Tankage. HFRM’s use of the Jayhawk Tankage will be added to this Agreement as an amendment with all terms and conditions being consistent with this Agreement, and thereafter the term “El Dorado Crude Tankage” as used herein shall include the Jayhawk Tankage.

6. Right to Refuse. HEP Operating reserves the right to refuse receipt of any Product into the El Dorado Terminal, alternatively route such Product to another location, or take other appropriate action in regards to such Product if Product does not meet the El Dorado Quality Specifications.

Exhibit K-2

HFRM, if requested in writing, will provide HEP Operating with notice setting forth the quantity, quality, and specifications of Product to be delivered a minimum of four (4) hours prior to any delivery to the El Dorado Terminal. Any reasonable costs incurred by HEP Operating in connection with addressing or handling HFRM’s Product that does not meet the El Dorado Quality Specifications shall be borne by HFRM.

7. Terminal Damage or Destruction. If any part of the El Dorado Terminal or the El Dorado Crude Tankage are damaged or destroyed by fire or other casualty, HEP Operating shall have the discretion to reduce receipts into and deliveries out of the El Dorado Terminal and to allocate any remaining El Dorado Terminal capacity and throughput fairly and reasonably among various customers utilizing terminalling services at the El Dorado Terminal. HEP Operating may, but shall not be obligated to, repair or replace such damaged or destroyed terminal facilities or Tanks.

8. Delivery Lines. The El Dorado Crude Tankage is connected to the El Dorado Refinery by two 16” delivery lines, together with associated piping necessary for Product movements into and out of the El Dorado Crude Tankage (the “El Dorado Delivery Lines”). HEP Operating will operate the El Dorado Delivery Lines for HFRM’s exclusive use. HEP Operating will operate one of the 16” El Dorado Delivery Lines for Product movements from the El Dorado Crude Tankage to the El Dorado Refinery with a capacity to deliver (a) 130,000 bpd based on a maximum viscosity of 350 SUS at 60 degrees Fahrenheit when operating only one El Dorado Delivery Line, and (b) 165,000 bpd based on a maximum viscosity of 350 SUS at 60 degrees Fahrenheit when operating both El Dorado Delivery Lines. HEP Operating will operate the other 16” El Dorado Delivery Line for bidirectional use. HEP Operating will maintain the El Dorado Delivery Lines to gravity feed Product to the El Dorado Refinery or, upon request of HFRM, to pump Product to the El Dorado Refinery at a pressure of at least 25 psig (when operating one El Dorado Delivery Line) and 50 psig (when operating both El Dorado Delivery Lines), as measured at the El Dorado Refinery receipt point. HEP Operating will maintain at least two (2) full-sized pumps for this service and will operate the pumps at HFRM’s request.

9. Products Testing. At HFRM’s request and upon HEP Operating’s approval, such approval not to be unreasonably withheld, delayed or conditioned, HEP Operating shall provide sampling and testing services for HFRM’s Products at the El Dorado Terminal. All fees for Product testing shall be billed to HFRM at HEP Operating’s actual cost.

Exhibit K-3

Exhibit L-2

to

Third Amended and Restated

Master Throughput Agreement

Special Provisions:

Tulsa West Tankage

1.XO Maintenance Operating Expense Adjustment. At the end of the Applicable Term, HEP Operating shall calculate the aggregate XO maintenance operating expenses incurred for the Tulsa West Tankage (“Actual OPEX”). In the event that the Actual OPEX exceeds the Assumed OPEX for the Tulsa West Tankage set forth on Exhibit C, HFRM shall, within ten (10) days of receiving an invoice from HEP Operating, reimburse HEP Operating an amount equal to (i) the Actual OPEX minus (ii) the Assumed OPEX (the “OPEX Reimbursement Amount”). In the event that the Actual OPEX is less than the Assumed OPEX for the Tulsa West Tankage set forth on Exhibit C, no adjustments shall be made and no amounts shall be reimbursed.

2.Tank Inspections. Except with respect to Tanks 186 and 187, HFRM will reimburse HEP Operating for the cost of performing the first API 653 inspection on each of the tanks included in the Tulsa West Tankage and any repairs or tests or consequential remediation that may be required to be made to such assets as a result of any discovery made during such inspection.

Exhibit L-2

EX-31.1

Exhibit 31.1

CERTIFICATION

I, George J. Damiris, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Holly Energy Partners, L.P;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2018	/s/ George J. Damiris
	George J. Damiris
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard L. Voliva III, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Holly Energy Partners, L.P;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2018	/s/ Richard L. Voliva III
	Richard L. Voliva III
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE

OFFICER OF HOLLY ENERGY PARTNERS, L.P.

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-Q for the quarterly period ended June 30, 2018 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George J. Damiris, Chief Executive Officer of Holly Logistic Services, L.L.C., the general partner of HEP Logistics Holdings, L.P., the general partner of Holly Energy Partners, L.P (the “Company”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 2, 2018	/s/ George J. Damiris
	George J. Damiris
	Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL

OFFICER OF HOLLY ENERGY PARTNERS, L.P.

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-Q for the quarterly period ended June 30, 2018 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard L. Voliva III, Chief Financial Officer of Holly Logistic Services, L.L.C., the general partner of HEP Logistics Holdings, L.P., the general partner of Holly Energy Partners, L.P (the “Company”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 2, 2018	/s/ Richard L. Voliva III
	Richard L. Voliva III
	Executive Vice President and Chief Financial Officer

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Document Entity Information - USD ($)	6 Months Ended
	Jun. 30, 2018	Jul. 27, 2018	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	HOLLY ENERGY PARTNERS LP
Entity Central Index Key	0001283140
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		105,440,201
Entity Public Float			$ 1,200,000,000

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 6,656	$ 7,776
Accounts receivable:
Trade	13,501	12,803
Affiliates	36,665	51,501
Total accounts receivable	50,166	64,304
Prepaid and other current assets	3,146	2,311
Total current assets	59,968	74,391
Properties and equipment, net	1,551,709	1,569,471
Intangible assets, net	121,935	129,463
Goodwill	270,336	266,716
Equity method investments	84,752	85,279
Other assets	27,363	28,794
Total assets	2,116,063	2,154,114
Accounts payable:
Trade	9,148	14,547
Affiliates	11,250	7,725
Total accounts payable	20,398	22,272
Accrued interest	13,189	13,256
Deferred revenue	10,845	9,598
Accrued property taxes	5,540	4,652
Other current liabilities	3,593	5,707
Total current liabilities	53,565	55,485
Long-term debt	1,395,599	1,507,308
Other long-term liabilities	15,526	15,843
Deferred revenue	48,405	47,272
Class B unit	44,600	43,141
Partners’ equity:
Common unitholders (105,440,201 and 101,568,955 units issued and outstanding at June 30, 2018 and December 31, 2017, respectively)	468,397	393,959
Noncontrolling interest	89,971	91,106
Total Equity	558,368	485,065
Total liabilities and equity	$ 2,116,063	$ 2,154,114

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Consolidated Balance Sheets (Parenthetical) - shares	Jun. 30, 2018	Dec. 31, 2017
Partners' Equity:
Common units issued (in shares)	105,440,201	101,568,955
Common units outstanding (in shares)	105,440,201	101,568,955

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Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues:
Affiliates	$ 94,013	$ 93,152	$ 195,441	$ 182,177
Third parties	24,747	15,991	52,203	32,600
Total revenues	118,760	109,143	247,644	214,777
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	34,533	34,097	70,735	66,586
Depreciation and amortization	24,608	19,945	49,750	38,722
General and administrative	2,673	2,615	5,795	5,249
Total operating costs and expenses	61,814	56,657	126,280	110,557
Operating income	56,946	52,486	121,364	104,220
Other income (expense):
Equity in earnings of equity method investments	1,734	4,053	3,013	5,893
Interest expense	(17,626)	(13,748)	(35,207)	(27,287)
Interest income	526	103	1,041	205
Loss on early extinguishment of debt	0	0	0	(12,225)
Gain (loss) on sale of assets and other	(53)	89	33	162
Total other income (expense)	(15,419)	(9,503)	(31,120)	(33,252)
Income before income taxes	41,527	42,983	90,244	70,968
State income tax benefit (expense)	(28)	(127)	(110)	(233)
Net Income	41,499	42,856	90,134	70,735
Allocation of net income attributable to noncontrolling interests	(1,356)	(1,521)	(3,823)	(3,837)
Net income attributable to the partners	40,143	41,335	86,311	66,898
General partner interest in net income attributable to the Partnership, including incentive distributions	0	(18,328)	0	(35,466)
Limited partners’ interest in net income	$ 40,143	$ 23,007	$ 86,311	$ 31,432
Limited partners’ per unit interest in earnings—basic and diluted (in dollars per share)	$ 0.38	$ 0.36	$ 0.82	$ 0.49
Weighted average limited partners’ units outstanding (in shares)	105,429	64,086	104,637	63,602

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Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 41,499	$ 42,856	$ 90,134	$ 70,735
Other comprehensive income:
Change in fair value of cash flow hedging instruments	0	11	0	87
Reclassification adjustment to net income on partial settlement of cash flow hedge	0	(102)	0	(115)
Other comprehensive income	0	(91)	0	(28)
Comprehensive income before noncontrolling interest	41,499	42,765	90,134	70,707
Allocation of net comprehensive income to noncontrolling interests	(1,356)	(1,521)	(3,823)	(3,837)
Comprehensive income attributable to the partners	$ 40,143	$ 41,244	$ 86,311	$ 66,870

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities
Net income	$ 90,134	$ 70,735
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	49,750	38,722
(Gain) loss on sale of assets	(183)	(133)
Amortization of deferred charges	1,516	1,504
Equity-based compensation expense	1,550	1,109
Equity in earnings of equity method investments, net of distributions	228	594
Loss on early extinguishment of debt	0	12,225
(Increase) decrease in operating assets:
Accounts receivable – trade	(698)	(285)
Accounts receivable – affiliates	14,836	6,033
Prepaid and other current assets	(835)	(234)
Increase (decrease) in operating liabilities:
Accounts payable – trade	(1,428)	104
Accounts payable – affiliates	(3,546)	9,128
Accrued interest	(67)	(7,519)
Deferred revenue	3,700	1,653
Accrued property taxes	888	(1,001)
Other current liabilities	(2,023)	(442)
Other, net	49	(336)
Net cash provided by operating activities	160,963	113,601
Cash flows from investing activities
Additions to properties and equipment	(24,739)	(20,524)
Other Payments to Acquire Businesses	(6,831)	0
Proceeds from sale of assets	196	635
Distributions in excess of equity in earnings of equity investments	299	1,654
Net cash used for investing activities	(31,075)	(18,235)
Cash flows from financing activities
Borrowings under credit agreement	305,500	479,000
Repayments of credit agreement borrowings	(417,500)	(189,000)
Redemption of 6.5% Senior Notes	0	(309,750)
Proceeds from Issuance of common units	114,831	52,634
Distributions to HEP unitholders	(130,075)	(112,195)
Distributions to noncontrolling interests	(3,500)	(3,500)
Distribution to HFC for El Dorado tanks	0	(103)
Contributions from general partner	492	995
Units withheld for tax withholding obligations	(58)	(35)
Other	(698)	(730)
Net cash used by financing activities	(131,008)	(82,684)
Cash and cash equivalents
Increase (decrease) for the period	(1,120)	12,682
Beginning of period	7,776	3,657
End of period	$ 6,656	$ 16,339

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Consolidated Statement of Equity - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands	Total	Common Units	Noncontrolling Interest
Balance, Beginning of Period at Dec. 31, 2017	$ 485,065	$ 393,959	$ 91,106
Increase (Decrease) in Partners' Equity [Roll Forward]
Issuance of common units	114,900	114,900
Distributions to HEP unitholders	(130,075)	(130,075)
Distributions to noncontrolling interest	(3,500)		(3,500)
Amortization of restricted and performance units	1,550	1,550
Class B unit accretion	(1,459)	(1,459)
Cumulative transition adjustment for adoption of revenue recognition standard	1,320	1,320
Other	433	433
Net income	90,134	87,769	2,365
Balance, End of Period at Jun. 30, 2018	$ 558,368	$ 468,397	$ 89,971

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Description of Business and Presentation of Financial Statements

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Description of Business and Presentation of Financial Statements

Description of Business and Presentation of Financial Statements

Holly Energy Partners, L.P. (“HEP”), together with its consolidated subsidiaries, is a publicly held master limited partnership. As of June 30, 2018, HollyFrontier Corporation (“HFC”) and its subsidiaries own a 57% limited partner interest and the non-economic general partner interest in HEP. We commenced operations on July 13, 2004, upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights (“IDRs”) held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions. As a result of this transaction, no distributions were made on the general partner interest after October 31, 2017.

On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partner interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under our revolving credit facility.

We own and operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support HFC’s refining and marketing operations in the Mid-Continent, Southwest and Northwest regions of the United States and Delek US Holdings, Inc.’s (“Delek”) refinery in Big Spring, Texas. Additionally, we own a 75% interest in UNEV Pipeline, LLC (“UNEV”), a 50% interest in the Osage Pipe Line Company, LLC (“Osage”) and a 50% interest in the Cheyenne Pipeline LLC.

We operate in two reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note 15.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons, providing other services at our storage tanks and terminals and by charging fees for processing hydrocarbon feedstocks through our refinery processing units. We do not take ownership of products that we transport, terminal, store or process, and therefore, we are not exposed directly to changes in commodity prices.

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2017. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2018.

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of subsidiaries and joint ventures that we control. All significant intercompany transactions and balances have been eliminated.

Most of our acquisitions from HFC occurred while we were a consolidated variable interest entity (“VIE”) of HFC. Therefore, as an entity under common control with HFC, we recorded these acquisitions on our balance sheets at HFC's historical basis instead of our purchase price or fair value.

Accounting Pronouncements Adopted During the Periods Presented

Share-Based Compensation

In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for

tax withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in our operating activities. The impact of this change for the six months ended June 30, 2017 was not material to our consolidated statement of cash flows. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard had an effective date of January 1, 2018, and we accounted for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment was recorded to retained earnings as of the date of initial application. In preparing

for adoption, we evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we implemented policies to comply with this new standard. See Note 3 for additional information on our revenue recognition policies.

Business Combinations

In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accounting for identifiable intangible assets in business combinations. This standard had an effective date of January 1, 2018, and had no effect on our financial condition, results of operations or cash flows.

Financial Assets and Liabilities

In January 2016, an accounting standard update was issued requiring changes in the accounting and disclosures for financial instruments. This standard was effective beginning with our 2018 reporting year and had no effect on our financial condition, results of operations or cash flows.

Accounting Pronouncements Not Yet Adopted

Leases

In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. In preparing for adoption, we have identified, reviewed and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired software and are implementing systems to facilitate lease capture and related accounting treatment.

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Acquisitions

6 Months Ended

Jun. 30, 2018

Business Combinations [Abstract]

Acquisitions

Acquisitions

SLC Pipeline and Frontier Aspen

On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline LLC (“SLC Pipeline”) and the remaining 50% interest in Frontier Aspen LLC (“Frontier Aspen”) from subsidiaries of Plains All American Pipeline, L,P. (“Plains”), for cash consideration of $250 million. Prior to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a result of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.

These acquisitions were accounted for as a business combination achieved in stages. Our pre-existing equity method investments in SLC Pipeline and Frontier Aspen were remeasured at an acquisition date fair value of $112 million since we now have a controlling interest, and we recognized a gain on the remeasurement in the fourth quarter of 2017 of $36.3 million. The fair value of our pre-existing equity method investments in SLC Pipeline and Frontier Aspen was estimated using Level 3 Inputs under the income method for these entities, adjusted for lack of control and marketability.

The total consideration of $363.8 million, consisting of initial cash consideration of $250 million, working capital adjustments of $1.8 million and the fair value of our preexisting equity method investments in SLC Pipeline and Frontier Aspen of $112 million, was allocated to the acquisition date fair value of assets and liabilities acquired as of the October 31, 2017 acquisition date, with the excess purchase price recorded as goodwill. The following summarizes the value of assets and liabilities acquired:

	(in thousands)
Cash and cash equivalents	$	4,609
Accounts receivable	5,164
Prepaid and other current assets	8
Properties and equipment	275,061
Intangible assets	70,182
Goodwill	13,845
Accounts payable	(3,598		)
Accrued property taxes	(1,438		)
Net assets acquired	$	363,833

SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal

of the Frontier Pipeline (defined below) and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah (the “Frontier Pipeline”) that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.

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Revenues

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenues

Revenues

Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) it is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. Therefore, we bifurcate the consideration received between lease and service revenue. The service component is within the scope of Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09.

Several of our contracts include incentive or reduced tariffs once a certain quarterly volume is met. Revenue from the variable element of these transactions is recognized based on the actual volumes shipped as it relates specifically to rendering the services during the applicable quarter.

We adopted the new revenue recognition standard (see Note 1) using the modified retrospective method, whereby the cumulative effect of applying the new standard was recorded as an adjustment to the opening balance of retained earnings as well as the carrying amounts of assets and liabilities as of January 1, 2018, which had no impact on our cash flows. The following table reflects the cumulative effect of adoption as of January 1, 2018:

	Prior to Adoption		Increase (Decrease)			As Adjusted
	(In millions)
Deferred revenue	$	9,598	$	(1,320	)	$	8,278
Partners’ equity: Common unitholders	$	393,959	$	1,320		$	395,279

The majority of our long-term transportation contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of shipments in the event a customer ships below their contractual requirements. If there are no future performance obligations, we will recognize these deficiency payments in revenue.

In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize the service portion of these deficiency payments in revenue when we do not expect we will be required to satisfy these performance obligations in the future based on the pattern of rights exercised by the customer. During the three and six months ended June 30, 2018, we recognized $3.4 million and $7.0 million, respectively, of these deficiency payments in revenue, of which $0.4 million and $2.6 million, respectively, related to deficiency payments billed in prior periods. As of June 30, 2018, deferred revenue reflected in our consolidated balance sheet related to shortfalls billed was $4.4 million.

	June 30, 2018			January 1, 2018
	(In thousands)
Contract asset	$	1,562		$	—
Contract liability	$	(4,441	)	$	(2,713	)

The contract assets and liabilities include both lease and service components. We recognized $0.4 million and $2.6 million in revenue during the three and six months ended June 30, 2018, respectively, that was previously included in contract liability as of January 1, 2018.

As of June 30, 2018, we expect to recognize $2.4 billion in revenue related to our unfulfilled performance obligations under the terms of our long-term throughput agreements and operating leases expiring in 2019 through 2036. These agreements provide for changes in the minimum revenue guarantees annually for increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index, with certain contracts having provisions that limit the level of the rate increases or decreases. We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and lease revenues):

Years Ending December 31,	(In millions)
Remainder of 2018	$	188
2019	352
2020	305
2021	294
2022	267
Thereafter	1,042
Total	$	2,448

Payment terms under our contracts with customers are consistent with industry norms and are typically payable within 10 to 30 days of the date of invoice.

Disaggregated revenues are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
Pipelines	$	65,539	$	55,248	$	137,708	$	107,695
Terminals, tanks and loading racks	34,386		36,356		72,567		70,163
Refinery processing units	18,835		17,539		37,369		36,919
	$	118,760	$	109,143	$	247,644	$	214,777

During the three and six months ended June 30, 2018, lease revenues amounted to $68.1 million and $138.7 million, respectively, and service revenues amounted to $50.7 million and $109.0 million, respectively. Both of these revenues were recorded within affiliates and third parties revenues on our consolidated statement of income.

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Financial Instruments

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Financial Instruments

Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of these instruments. Debt consists of outstanding principal under our revolving credit agreement (which approximates fair value as interest rates are reset frequently at current interest rates) and our fixed interest rate senior notes.

Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

• (Level 1) Quoted prices in active markets for identical assets or liabilities.

• (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

• (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

The carrying amounts and estimated fair values of our senior notes were as follows:

		June 30, 2018				December 31, 2017
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Liabilities:
6% Senior notes	Level 2	495,599		507,025		495,308		525,120
		$	495,599	$	507,025	$	495,308	$	525,120

Level 2 Financial Instruments

Our senior notes are measured at fair value using Level 2 inputs. The fair value of the senior notes is based on market values provided by a third-party bank, which were derived using market quotes for similar type debt instruments. See Note 8 for additional information.

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Properties and Equipment

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Properties and Equipment

Properties and Equipment

The carrying amounts of our properties and equipment are as follows:

	June 30, 2018		December 31, 2017
	(In thousands)
Pipelines, terminals and tankage	$	1,525,033	$	1,541,722
Refinery assets	347,338		347,338
Land and right of way	85,960		86,484
Construction in progress	42,811		12,029
Other	40,420		35,659
	2,041,562		2,023,232
Less accumulated depreciation	489,853		453,761
	$	1,551,709	$	1,569,471

We capitalized $0.2 million and $0.4 million during the six months ended June 30, 2018 and 2017, respectively, in interest attributable to construction projects.

Depreciation expense was $41.9 million and $34.9 million for the six months ended June 30, 2018 and 2017, respectively, and includes depreciation of assets acquired under capital leases.

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Intangible Assets

6 Months Ended

Jun. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Intangible Assets

Intangible assets include transportation agreements and customer relationships that represent a portion of the total purchase price of certain assets acquired from Delek in 2005, from HFC in 2008 prior to HEP becoming a consolidated VIE of HFC and from Plains in 2017.

The carrying amounts of our intangible assets are as follows:

	Useful Life	June 30, 2018		December 31, 2017
		(In thousands)
Delek transportation agreement	30 years	$	59,933	$	59,933
HFC transportation agreement	10-15 years	75,131		75,131
Customer relationships	10 years	69,282		69,282
Other		50		50
		204,396		204,396
Less accumulated amortization		82,461		74,933
		$	121,935	$	129,463

Amortization expense was $7.5 million and $3.5 million for the six months ended June 30, 2018 and 2017, respectively. We estimate amortization expense to be $14.0 million for each of the next four years and $9.8 million in 2023.

We have additional transportation agreements with HFC resulting from historical transactions consisting of pipeline, terminal and tankage assets contributed to us or acquired from HFC. These transactions occurred while we were a consolidated VIE of HFC; therefore, our basis in these agreements is zero and does not reflect a step-up in basis to fair value.

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Employees, Retirement and Incentive Plans

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employees, Retirement and Incentive Plans

Employees, Retirement and Incentive Plans

Direct support for our operations is provided by Holly Logistic Services, L.L.C. (“HLS”), an HFC subsidiary, which utilizes personnel employed by HFC who are dedicated to performing services for us. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $1.6 million and $1.3 million for the three months ended June 30, 2018 and 2017, respectively, and $3.4 million and $3.0 million for the six months ended June 30, 2018 and 2017, respectively.

Under HLS’s secondment agreement with HFC (the “Secondment Agreement”), certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs related to these employees.

We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted or phantom units, performance units, unit options and unit appreciation rights. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (a significant proportion of our awards) is to expense the costs ratably over the vesting periods.

As of June 30, 2018, we had two types of incentive-based awards outstanding, which are described below. The compensation cost charged against income was $0.7 million and $0.6 million for the three months ended June 30, 2018 and 2017, respectively, and $1.5 million and $0.9 million for the six months ended June 30, 2018 and 2017, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of June 30, 2018, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,323,787 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.

Restricted and Phantom Units

Under our Long-Term Incentive Plan, we grant restricted units to non-employee directors and phantom units to selected employees who perform services for us, with most awards vesting over a period of one to three years. We previously granted restricted units to selected employees who perform services for us, which vest over a period of three years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution rights on these units from the date of grant, and the recipients of the restricted units have voting rights on the restricted units from the date of grant.

The fair value of each restricted or phantom unit award is measured at the market price as of the date of grant and is amortized on a straight-line basis over the requisite service period for each separately vesting portion of the award.

A summary of restricted and phantom unit activity and changes during the six months ended June 30, 2018, is presented below:

Restricted and Phantom Units	Units		Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2018 (nonvested)	119,009		$	34.77
Granted	12,890		30.23
Forfeited	(698	)	34.59
Outstanding at June 30, 2018 (nonvested)	131,201		$	34.33

No restricted units were vested and transferred to recipients during the six months ended June 30, 2018. As of June 30, 2018, there was $1.8 million of total unrecognized compensation expense related to unvested restricted and phantom unit grants, which is expected to be recognized over a weighted-average period of 1.2 years.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected officers who perform services for us. Performance units granted are payable in common units at the end of a three-year performance period based upon the growth in our distributable cash flow per common unit over the performance period. As of June 30, 2018, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target number of performance units granted.

We granted 2,764 performance units during the six months ended June 30, 2018. Performance units granted in 2017 and 2018 vest over a three-year performance period ending December 31, 2020 and 2021, respectively, and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, and can range from 50% to 150% of the target number of performance units granted. Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the common units from the date of grant.

A summary of performance unit activity and changes for the six months ended June 30, 2018, is presented below:

Performance Units	Units
Outstanding at January 1, 2018 (nonvested)	36,911
Granted	2,764
Vesting and transfer of common units to recipients	(4,283	)
Outstanding at June 30, 2018 (nonvested)	35,392

The grant date fair value of performance units vested and transferred to recipients during both the six months ended June 30, 2018 and 2017 was $0.1 million. Based on the weighted-average fair value of performance units outstanding at June 30, 2018, of $1.2 million, there was $0.7 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.6 years.

During the six months ended June 30, 2018, we did not purchase any common units in the open market for the issuance and

settlement of unit awards under our Long-Term Incentive Plan.

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Debt

6 Months Ended

Jun. 30, 2018

Debt Instruments [Abstract]

Debt

Debt

Credit Agreement

We have a $1.4 billion senior secured revolving credit facility (the “Credit Agreement”) expiring in July 2022. The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Credit Agreement is also available to fund letters of credit up to a $50 million sub-limit, and it contains an accordion feature giving us the ability to increase the size of the facility by up to $300 million with additional lender commitments.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets, and indebtedness under the Credit Agreement is guaranteed by our material, wholly-owned subsidiaries.  The Credit Agreement requires us to maintain compliance with certain financial covenants consisting of total leverage, senior secured leverage, and interest coverage.  It also limits or restricts our ability to engage in certain activities.  If, at any time prior to the expiration of the Credit Agreement, HEP obtains two investment grade credit ratings, the Credit Agreement will become unsecured and many of the covenants, limitations, and restrictions will be eliminated.

We may prepay all loans at any time without penalty, except for tranche breakage costs.  If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies.  We were in compliance with the covenants as of June 30, 2018.

Senior Notes

On July 19, 2016, we closed a private placement of $400 million in aggregate principal amount of 6% senior unsecured notes due in 2024 (the “ 6% Senior Notes”). On September 22, 2017, we closed a private placement of an additional $100 million in aggregate principal amount of the 6% Senior Notes for a combined aggregate principal amount outstanding of $500 million maturing in 2024.

The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of June 30, 2018. At any time when the 6% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6% Senior Notes.

Indebtedness under the 6% Senior Notes is guaranteed by our wholly-owned subsidiaries.

On January 4, 2017, we redeemed the $300 million aggregate principal amount of 6.5% senior notes due in 2020 (the “6.5% Senior Notes”) at a redemption cost of $309.8 million at which time we recognized a $12.2 million early extinguishment loss consisting of a $9.8 million debt redemption premium and unamortized discount and financing costs of $2.4 million. We funded the redemption with borrowings under our Credit Agreement.

Long-term Debt

The carrying amounts of our long-term debt are as follows:

	June 30, 2018			December 31, 2017
	(In thousands)
Credit Agreement
Amount outstanding	$	900,000		$	1,012,000
6% Senior Notes
Principal	500,000			500,000
Unamortized premium and debt issuance costs	(4,401		)	(4,692		)
	495,599			495,308
Total long-term debt	$	1,395,599		$	1,507,308

Interest Rate Risk Management

The two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement advances matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Six Months Ended June 30,
	2018		2017
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	17,850	$	13,299
6.5% Senior Notes	—		162
6% Senior Notes	15,000		12,000
Amortization of discount and deferred debt issuance costs	1,516		1,536
Commitment fees and other	1,007		720
Total interest incurred	35,373		27,717
Less capitalized interest	166		430
Net interest expense	$	35,207	$	27,287
Cash paid for interest	$	33,935	$	33,700

Capital Lease Obligations

We have capital lease obligations related to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under capital leases was $5.7 million and $5.1 million as of June 30, 2018 and December 31, 2017, respectively, with accumulated depreciation of $3.7 million and $3.3 million as of June 30, 2018 and December 31, 2017, respectively. We include depreciation of capital leases in depreciation and amortization in our consolidated statements of income.

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Significant Customers

6 Months Ended

Jun. 30, 2018

Risks and Uncertainties [Abstract]

Significant Customers

Significant Customers

All revenues are domestic revenues, of which 86% are currently generated from our two largest customers: HFC and Delek.

The following table presents the percentage of total revenues generated by each of these customers:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
HFC	79	%	85	%	79	%	85	%
Delek	7	%	6	%	6	%	7	%

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Related Party Transactions

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

We serve HFC’s refineries under long-term pipeline, terminal and tankage throughput agreements, and refinery processing unit tolling agreements expiring from 2019 to 2036. Under these agreements, HFC agrees to transport, store and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminals, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual rate adjustments on July 1st each year generally based on increases or decreases in PPI or the FERC index. As of June 30, 2018, these agreements with HFC require minimum annualized payments to us of $334.5 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of these agreements, a shortfall payment may be applied as a credit in the following four quarters after its minimum obligations are met.

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee (currently $2.5 million) for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are charged to us separately by HFC. Also, we reimburse HFC and its affiliates for direct expenses they incur on our behalf.

Related party transactions with HFC are as follows:

• Revenues received from HFC were $94.0 million and $93.2 million for the three months ended June 30, 2018 and 2017, respectively, and $195.4 million and $182.2 million for the six months ended June 30, 2018 and 2017, respectively.

• HFC charged us general and administrative services under the Omnibus Agreement of $0.6 million for each of the three months ended June 30, 2018 and 2017, and $1.2 million for the six months ended June 30, 2018 and 2017.

• We reimbursed HFC for costs of employees supporting our operations of $12.5 million and $11.4 million for the three months ended June 30, 2018 and 2017, respectively, and $25.2 million and $22.9 million for the six months ended June 30, 2018 and 2017, respectively.

• HFC reimbursed us $2.9 million and $1.5 million for the three months ended June 30, 2018 and 2017, respectively, for expense and capital projects and $4.2 million and $2.8 million for the six months ended June 30, 2018 and 2017, respectively.

• We distributed $36.6 million and $72.8 million in the three and six months ended June 30, 2018, respectively, to HFC as regular distributions on its common units and $32.6 million and $63.9 million on its common units and general partner interest, including general partner incentive distributions, in the three and six months ended June 30, 2017, respectively.

• Accounts receivable from HFC were $36.7 million and $51.5 million at June 30, 2018, and December 31, 2017, respectively.

• Accounts payable to HFC were $11.3 million and $7.7 million at June 30, 2018, and December 31, 2017, respectively.

• Deferred revenue in the consolidated balance sheets at June 30, 2018 and December 31, 2017, includes $1.7 million and $4.4 million, respectively, relating to certain shortfall billings to HFC. It is possible that HFC may not exceed its minimum obligations to receive credit for any of the $1.7 million deferred at June 30, 2018.

• We received lease payments from HFC for use of our Artesia and Tulsa railyards of $0.5 million and $0.1 million for the three months ended June 30, 2018 and 2017, respectively, and $1.0 million and $0.2 million for the six months ended June 30, 2018 and 2017, respectively.

• On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics, a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions.

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Partners' Equity, Income Allocations and Cash Distributions

6 Months Ended

Jun. 30, 2018

Partners' Capital [Abstract]

Partners' Equity, Income Allocations and Cash Distributions

Partners’ Equity, Income Allocations and Cash Distributions

As of June 30, 2018, HFC held 59,630,030 of our common units, constituting a 57% limited partner interest in us, and held the

non-economic general partner interest. Additionally, HEP Logistics, our general partner, owned all incentive distribution rights through October 31, 2017, at which time we closed on an equity restructuring transaction with HEP Logistics pursuant to which the incentive distribution rights were canceled. See Note 1 for a description of this equity restructuring transaction.

On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partnership interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under our Credit Agreement.

Continuous Offering Program

We have a continuous offering program under which we may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. For the six months ended June 30, 2018, HEP issued 171,246 units under this program, providing approximately $5.2 million in gross proceeds. As of June 30, 2018, HEP has issued 2,413,153 units under this program, providing $82.3 million in gross proceeds.

We intend to use our net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. Amounts repaid under our credit facility may be reborrowed from time to time.

Allocations of Net Income

Net income attributable to HEP is allocated to the partners based on their weighted-average ownership percentage during the period.

Prior to the equity restructuring of the general partner interest owned by HEP Logistics described in Note 1 that occurred on October 31, 2017, net income attributable to HEP was allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner included incentive distributions that were declared subsequent to quarter end. After incentive distributions and other priority allocations were allocated to the general partner, the remaining net income attributable to HEP was allocated to the partners based on their weighted-average ownership percentage during the period.

The following table presents the allocation of the general partner interest in net income for the periods presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
General partner interest in net income	$	—	$	827	$	—	$	1,338
General partner incentive distribution	—		17,501		—		34,128
Total general partner interest in net income	$	—	$	18,328	$	—	$	35,466

Cash Distributions

On July 19, 2018, we announced our cash distribution for the second quarter of 2018 of $0.66 per unit. The distribution is payable on all common units and will be paid August 9, 2018, to all unitholders of record on July 30, 2018. However, HEP Logistics will waive $2.5 million in limited partner cash distributions in accordance with the equity restructuring discussed in Note 1.

Prior to the equity restructuring of the general partner interest owned by HEP Logistics that occurred on October 31, 2017, our general partner, HEP Logistics, was entitled to incentive distributions if the amount we distributed with respect to any quarter exceeded specified target levels. After the restructuring of the general partner interest, the general partner interest was no longer entitled to any distributions.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands, except per unit data)
General partner interest in distribution	$	—	$	1,188	$	—	$	2,336
General partner incentive distribution	—		17,501		—		34,128
Total general partner distribution	—		18,689		—		36,464
Limited partner distribution	67,091		40,682		133,670		80,314
Total regular quarterly cash distribution	$	67,091	$	59,371	$	133,670	$	116,778
Cash distribution per unit applicable to limited partners	$	0.6600	$	0.6325	$	1.3150	$	1.2525

As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to HEP because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to HEP. Additionally, if the asset contributions and acquisitions from HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost, in excess of HFC’s historical basis in the transferred assets, would have been recorded in our financial statements at the time of acquisition as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

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Net Income per Limited Partner Unit

6 Months Ended

Jun. 30, 2018

Net Income per Limited Partner Unit [Abstract]

Net Income Per Limited Partner Unit

Net Income Per Limited Partner Unit

Net income per unit applicable to the limited partners is computed using the two-class method, since we have more than one participating security (common units and restricted units). Prior to the equity restructuring transaction described in Note 1, which was effective October 31, 2017, we had participating securities which included the aforementioned common units and restricted units as well as general partner units and IDRs. After the equity restructuring, the general partner interest was no longer entitled to any distributions, and none were made on the general partner interest after October 31, 2017.

To the extent net income attributable to the partners exceeds or is less than cash distributions, this difference is allocated to the partners based on their weighted-average ownership percentage during the period, after consideration of any priority allocations of earnings. Our dilutive securities, restricted units, are immaterial for all periods presented.

For purposes of applying the two-class method, including the allocation of cash distributions in excess of earnings, net income per limited partner unit is computed as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Net income attributable to the partners	$	40,143		$	41,335		$	86,311		$	66,898
Less: General partner’s distribution declared (including IDRs)	—			(18,689		)	—			(36,464		)
Limited partner’s distribution declared on common units	(67,091		)	(40,682		)	(133,670		)	(80,314		)
Distributions in excess of net income attributable to the partners	$	(26,948	)	$	(18,036	)	$	(47,359	)	$	(49,880	)

	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Three Months Ended June 30, 2018
Net income attributable to the partners:
Distributions declared	$	—		$	67,091		$	67,091
Distributions in excess of net income attributable to the partners	—			(26,948		)	(26,948		)
Net income attributable to the partners	$	—		$	40,143		$	40,143
Weighted average limited partners' units outstanding				105,429
Limited partners' per unit interest in earnings - basic and diluted				$	0.38
Three Months Ended June 30, 2017
Net income attributable to the partners:
Distributions declared	$	18,689		$	40,682		$	59,371
Distributions in excess of net income attributable to the partners	(361		)	(17,675		)	(18,036		)
Net income attributable to the partners	$	18,328		$	23,007		$	41,335
Weighted average limited partners' units outstanding				64,086
Limited partners' per unit interest in earnings - basic and diluted				$	0.36

	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Six Months Ended June 30, 2018
Net income attributable to partnership:
Distributions declared	$	—		$	133,670		$	133,670
Distributions in excess of net income attributable to partnership	—			(47,359		)	(47,359		)
Net income attributable to partnership	$	—		$	86,311		$	86,311
Weighted average limited partners' units outstanding				104,637
Limited partners' per unit interest in earnings - basic and diluted				$	0.82
Six Months Ended June 30, 2017
Net income attributable to partnership:
Distributions declared	$	36,464		$	80,314		$	116,778
Distributions in excess of net income attributable to partnership	(998		)	(48,882		)	(49,880		)
Net income attributable to partnership	$	35,466		$	31,432		$	66,898
Weighted average limited partners' units outstanding				63,602
Limited partners' per unit interest in earnings - basic and diluted				$	0.49

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Environmental

6 Months Ended

Jun. 30, 2018

Accrual for Environmental Loss Contingencies [Abstract]

Environmental

Environmental

We expensed $0.3 million for the three and the six months ended June 30, 2018, for environmental remediation obligations, and we incurred no expenses for the three and six months ended June 30, 2017. The accrued environmental liability, net of expected recoveries from indemnifying parties, reflected in our consolidated balance sheets was $6.3 million and $6.5 million at June 30, 2018 and December 31, 2017, respectively, of which $4.7 million and $5.0 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time.

Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers. As of June 30, 2018 and December 31, 2017, our consolidated balance sheets included additional accrued environmental liabilities of $0.7 million and $0.8 million, respectively, for HFC indemnified liabilities, and other assets included equal and offsetting balances representing amounts due from HFC related to indemnifications for environmental remediation liabilities.

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Contingencies

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Contingencies

Contingencies

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

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Operating Segments

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Operating Segments

Operating Segments

Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in two operating segments: pipelines and terminals, and refinery processing units. These operating segments adhere to the accounting polices used for our consolidated financial statements.

The pipelines and terminals segment has been aggregated as both pipeline and terminals (1) have similar economic characteristics,(2) similarly provide logistics services of transportation and storage of petroleum products, (3) similarly support the petroleum refining business, including distribution of its products, (4) have principally the same customers and (5) are subject to similar regulatory requirements.

We evaluate the performance of each segment based on its respective operating income. Certain general and administrative expenses and interest and financing costs are excluded from segment operating income as they are not directly attributable to a specific operating segment. Identifiable assets are those used by the segment, whereas other assets are principally equity method investments, cash, deposits and other assets that are not associated with a specific reportable operating segment.

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Pipelines and terminals - affiliate	$	75,178		$	75,613		$	158,072		$	145,258
Pipelines and terminals - third-party	24,747			15,991			52,203			32,600
Refinery processing units - affiliate	18,835			17,539			37,369			36,919
Total segment revenues	$	118,760		$	109,143		$	247,644		$	214,777
Segment operating income:
Pipelines and terminals	$	51,004		$	49,164		$	111,217		$	95,649
Refinery processing units	8,615			5,937			15,942			13,820
Total segment operating income	59,619			55,101			127,159			109,469
Unallocated general and administrative expenses	(2,673		)	(2,615		)	(5,795		)	(5,249		)
Interest and financing costs, net	(17,100		)	(13,645		)	(34,166		)	(39,307		)
Equity in earnings of unconsolidated affiliates	1,734			4,053			3,013			5,893
Gain (loss) on sale of assets and other	(53		)	89			33			162
Income before income taxes	$	41,527		$	42,983		$	90,244		$	70,968
Capital Expenditures:
Pipelines and terminals	$	12,127		$	12,157		$	24,739		$	20,286
Refinery processing units	—			102			—			238
Total capital expenditures	$	12,127		$	12,259		$	24,739		$	20,524

	June 30, 2018		December 31, 2017
	(in thousands)
Identifiable assets:
Pipelines and terminals (1)	$	1,697,531	$	1,728,074
Refinery processing units	321,191		328,585
Other	97,341		97,455
Total identifiable assets	$	2,116,063	$	2,154,114

(1) Includes goodwill of $270.3 million and $266.7 million as of June 30, 2018 and December 31, 2017, respectively.

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Supplemental Guarantor / Non-Guarantor Financial Information

6 Months Ended

Jun. 30, 2018

Supplemental Guarantor / Non-Guarantor Financial Information [Abstract]

Supplemental Guarantor / Non-Guarantor Financial Information

Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of HEP (“Parent”) under the 6% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect 100% owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional, subject to certain customary release provisions. These circumstances include (i) when a Guarantor Subsidiary is sold or sells all or substantially all of its assets, (ii) when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, (iii) when a Guarantor Subsidiary’s guarantee of other indebtedness is terminated or released and (iv) when the requirements for legal defeasance or covenant defeasance or to discharge the senior notes have been satisfied.

The following financial information presents condensed consolidating balance sheets, statements of comprehensive income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting.

Condensed Consolidating Balance Sheet

June 30, 2018	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	640	$	6,014	$	—		$	6,656
Accounts receivable	—		45,447		5,305		(586		)	50,166
Prepaid and other current assets	156		2,629		361		—			3,146
Total current assets	158		48,716		11,680		(586		)	59,968
Properties and equipment, net	—		1,197,968		353,741		—			1,551,709
Investment in subsidiaries	1,866,892		269,911		—		(2,136,803		)	—
Intangible assets, net	—		121,935		—		—			121,935
Goodwill	—		270,336		—		—			270,336
Equity method investments	—		84,752		—		—			84,752
Other assets	10,483		16,880		—		—			27,363
Total assets	$	1,877,533	$	2,010,498	$	365,421	$	(2,137,389	)	$	2,116,063
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	19,284	$	1,700	$	(586	)	$	20,398
Accrued interest	13,189		—		—		—			13,189
Deferred revenue	—		9,675		1,170		—			10,845
Accrued property taxes	—		3,077		2,463		—			5,540
Other current liabilities	88		3,505		—		—			3,593
Total current liabilities	13,277		35,541		5,333		(586		)	53,565
Long-term debt	1,395,599		—		—		—			1,395,599
Other long-term liabilities	260		15,060		206		—			15,526
Deferred revenue	—		48,405		—		—			48,405
Class B unit	—		44,600		—		—			44,600
Equity - partners	468,397		1,866,892		269,911		(2,136,803		)	468,397
Equity - noncontrolling interest	—		—		89,971		—			89,971
Total liabilities and equity	$	1,877,533	$	2,010,498	$	365,421	$	(2,137,389	)	$	2,116,063

Condensed Consolidating Balance Sheet

December 31, 2017	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	511	$	7,263	$	—		$	7,776
Accounts receivable	—		59,448		5,038		(182		)	64,304
Prepaid and other current assets	13		2,016		282		—			2,311
Total current assets	15		61,975		12,583		(182		)	74,391
Properties and equipment, net	—		1,213,626		355,845		—			1,569,471
Investment in subsidiaries	1,902,285		273,319		—		(2,175,604		)	—
Intangible assets, net	—		129,463		—		—			129,463
Goodwill	—		266,716		—		—			266,716
Equity method investments	—		85,279		—		—			85,279
Other assets	11,753		17,041		—		—			28,794
Total assets	$	1,914,053	$	2,047,419	$	368,428	$	(2,175,786	)	$	2,154,114
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	20,928	$	1,526	$	(182	)	$	22,272
Accrued interest	12,500		756		—		—			13,256
Deferred revenue	—		8,540		1,058		—			9,598
Accrued property taxes	—		3,431		1,221		—			4,652
Other current liabilities	—		5,707		—		—			5,707
Total current liabilities	12,500		39,362		3,805		(182		)	55,485
Long-term debt	1,507,308		—		—		—			1,507,308
Other long-term liabilities	286		15,359		198		—			15,843
Deferred revenue	—		47,272		—		—			47,272
Class B unit	—		43,141		—		—			43,141
Equity - partners	393,959		1,902,285		273,319		(2,175,604		)	393,959
Equity - noncontrolling interest	—		—		91,106		—			91,106
Total liabilities and equity	$	1,914,053	$	2,047,419	$	368,428	$	(2,175,786	)	$	2,154,114

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	89,522		$	4,491		$	—		$	94,013
Third parties	—			19,540			5,207			—			24,747
	—			109,062			9,698			—			118,760
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			31,494			3,039			—			34,533
Depreciation and amortization				20,431			4,177			—			24,608
General and administrative	761			1,912			—			—			2,673
	761			53,837			7,216			—			61,814
Operating income (loss)	(761		)	55,225			2,482			—			56,946
Other income (expense):
Equity in earnings of subsidiaries	58,566			1,881			—			(60,447		)	—
Equity in earnings of equity method investments	—			1,734			—			—			1,734
Interest expense	(17,662		)	36			—			—			(17,626		)
Interest income	—			526			—			—			526
Gain on sale of assets and other	—			(79		)	26			—			(53		)
	40,904			4,098			26			(60,447		)	(15,419		)
Income before income taxes	40,143			59,323			2,508			(60,447		)	41,527
State income tax expense	—			(28		)	—			—			(28		)
Net income	40,143			59,295			2,508			(60,447		)	41,499
Allocation of net income attributable to noncontrolling interests	—			(729		)	(627		)	—			(1,356		)
Net income attributable to the partners	40,143			58,566			1,881			(60,447		)	40,143
Other comprehensive income	—			—			—			—			—
Comprehensive income attributable to the partners	$	40,143		$	58,566		$	1,881		$	(60,447	)	$	40,143

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	88,022		$	5,130		$	—		$	93,152
Third parties	—			10,385			5,606			—			15,991
	—			98,407			10,736			—			109,143
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			30,871			3,226			—			34,097
Depreciation and amortization	—			15,791			4,154			—			19,945
General and administrative	865			1,750			—			—			2,615
	865			48,412			7,380			—			56,657
Operating income (loss)	(865		)	49,995			3,356			—			52,486
Other income (expense):
Equity in earnings of subsidiaries	48,375			2,519			—			(50,894		)	—
Equity in earnings of equity method investments	—			4,053			—			—			4,053
Interest expense	(6,175		)	(7,573		)	—			—			(13,748		)
Interest income	—			103			—			—			103
Gain on sale of assets and other	—			87			2			—			89
	42,200			(811		)	2			(50,894		)	(9,503		)
Income before income taxes	41,335			49,184			3,358			(50,894		)	42,983
State income tax expense	—			(127		)	—			—			(127		)
Net income	41,335			49,057			3,358			(50,894		)	42,856
Allocation of net income attributable to noncontrolling interests	—			(682		)	(839		)	—			(1,521		)
Net income attributable to the partners	41,335			48,375			2,519			(50,894		)	41,335
Other comprehensive income	(91		)	(91		)	—			91			(91		)
Comprehensive income attributable to the partners	$	41,244		$	48,284		$	2,519		$	(50,803	)	$	41,244

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	183,813		$	11,628		$	—		$	195,441
Third parties	—			39,518			12,685			—			52,203
	—			223,331			24,313			—			247,644
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			64,158			6,577			—			70,735
Depreciation and amortization	—			41,432			8,318			—			49,750
General and administrative	2,041			3,754			—			—			5,795
	2,041			109,344			14,895			—			126,280
Operating income (loss)	(2,041		)	113,987			9,418			—			121,364
Other income (expense):
Equity in earnings (loss) of subsidiaries	123,618			7,093			—			(130,711		)	—
Equity in earnings of equity method investments	—			3,013			—			—			3,013
Interest expense	(35,311		)	104			—			—			(35,207		)
Interest income	—			1,041			—			—			1,041
Gain (loss) on sale of assets and other	45			(51		)	39			—			33
	88,352			11,200			39			(130,711		)	(31,120		)
Income (loss) before income taxes	86,311			125,187			9,457			(130,711		)	90,244
State income tax expense	—			(110		)	—			—			(110		)
Net income (loss)	86,311			125,077			9,457			(130,711		)	90,134
Allocation of net income attributable to noncontrolling interests	—			(1,459		)	(2,364		)	—			(3,823		)
Net income (loss) attributable to Holly Energy Partners	86,311			123,618			7,093			(130,711		)	86,311
Other comprehensive income (loss)	—			—			—			—			—
Comprehensive income (loss)	$	86,311		$	123,618		$	7,093		$	(130,711	)	$	86,311

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	168,798		$	13,379		$	—		$	182,177
Third parties	—			21,388			11,212			—			32,600
	—			190,186			24,591			—			214,777
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			59,963			6,623			—			66,586
Depreciation and amortization	—			30,644			8,078			—			38,722
General and administrative	2,020			3,229			—			—			5,249
	2,020			93,836			14,701			—			110,557
Operating income (loss)	(2,020		)	96,350			9,890			—			104,220
Other income (expense):
Equity in earnings (loss) of subsidiaries	93,658			7,420			—			(101,078		)	—
Equity in earnings of equity method investments	—			5,893			—			—			5,893
Interest expense	(12,515		)	(14,772		)	—			—			(27,287		)
Interest income	—			205			—			—			205
Loss on early extinguishment of debt	(12,225		)	—			—			—			(12,225		)
Gain (loss) on sale of assets and other	—			159			3			—			162
	68,918			(1,095		)	3			(101,078		)	(33,252		)
Income (loss) before income taxes	66,898			95,255			9,893			(101,078		)	70,968
State income tax expense	—			(233		)	—			—			(233		)
Net income (loss)	66,898			95,022			9,893			(101,078		)	70,735
Allocation of net income attributable to noncontrolling interests	—			(1,364		)	(2,473		)	—			(3,837		)
Net income (loss) attributable to Holly Energy Partners	66,898			93,658			7,420			(101,078		)	66,898
Other comprehensive income (loss)	(28		)	(28		)	—			28			(28		)
Comprehensive income (loss)	$	66,870		$	93,630		$	7,420		$	(101,050	)	$	66,870

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(33,588	)	$	182,983		$	18,661		$	(7,093	)	$	160,963
Cash flows from investing activities
Additions to properties and equipment	—			(18,829		)	(5,910		)	—			(24,739		)
Business and asset acquisitions	—			(6,831		)	—			—			(6,831		)
Distributions from UNEV in excess of earnings	—			3,407			—			(3,407		)	—
Proceeds from sale of assets	—			196			—			—			196
Distributions in excess of equity in earnings of equity investments	—			299			—			—			299
	—			(21,758		)	(5,910		)	(3,407		)	(31,075		)
Cash flows from financing activities
Net repayments under credit agreement	(112,000		)	—			—			—			(112,000		)
Net intercompany financing activities	160,330			(160,330		)	—			—			—
Proceeds from issuance of common units	114,899			(68		)	—			—			114,831
Contribution from general partner	492			—			—			—			492
Distributions to HEP unitholders	(130,075		)	—			—			—			(130,075		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Units withheld for tax withholding obligations	(58		)	—			—			—			(58		)
Other	—			(698		)	—			—			(698		)
	33,588			(161,096		)	(14,000		)	10,500			(131,008		)
Cash and cash equivalents
Increase (decrease) for the period	—			129			(1,249		)	—			(1,120		)
Beginning of period	2			511			7,263			—			7,776
End of period	$	2		$	640		$	6,014		$	—		$	6,656

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(20,377	)	$	122,025		$	19,373		$	(7,420	)	$	113,601
Cash flows from investing activities
Additions to properties and equipment	—			(17,670		)	(2,854		)	—			(20,524		)
Proceeds from sale of assets	—			635			—			—			635
Distributions from UNEV in excess of earnings	—			3,080			—			(3,080		)	—
Distributions in excess of equity in earnings of equity investments	—			1,654			—			—			1,654
	—			(12,301		)	(2,854		)	(3,080		)	(18,235		)
Cash flows from financing activities
Net borrowings under credit agreement	—			290,000			—			—			290,000
Net intercompany financing activities	389,005			(389,005		)	—			—			—
Redemption of senior notes	(309,750		)	—			—			—			(309,750		)
Proceeds from issuance of common units	52,383			251			—			—			52,634
Distributions to HEP unitholders	(112,195		)	—			—			—			(112,195		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Distribution to HFC for El Dorado tanks	(103		)	—			—			—			(103		)
Contributions from general partner	1,072			(77		)	—			—			995
Units withheld for tax withholding obligations	(35		)	—			—			—			(35		)
Other	—			(730		)	—			—			(730		)
	20,377			(99,561		)	(14,000		)	10,500			(82,684		)
Cash and cash equivalents
Decrease for the period	—			10,163			2,519			—			12,682
Beginning of period	2			301			3,354			—			3,657
End of period	$	2		$	10,464		$	5,873		$	—		$	16,339

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Description of Business and Presentation of Financial Statements (Policies)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Consolidation, Policy

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of subsidiaries and joint ventures that we control. All significant intercompany transactions and balances have been eliminated.

Most of our acquisitions from HFC occurred while we were a consolidated variable interest entity (“VIE”) of HFC. Therefore, as an entity under common control with HFC, we recorded these acquisitions on our balance sheets at HFC's historical basis instead of our purchase price or fair value.

New Accounting Pronouncements, Policy

Accounting Pronouncements Adopted During the Periods Presented

Share-Based Compensation

In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for

tax withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in our operating activities. The impact of this change for the six months ended June 30, 2017 was not material to our consolidated statement of cash flows. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard had an effective date of January 1, 2018, and we accounted for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment was recorded to retained earnings as of the date of initial application. In preparing

for adoption, we evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we implemented policies to comply with this new standard. See Note 3 for additional information on our revenue recognition policies.

Business Combinations

In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accounting for identifiable intangible assets in business combinations. This standard had an effective date of January 1, 2018, and had no effect on our financial condition, results of operations or cash flows.

Financial Assets and Liabilities

In January 2016, an accounting standard update was issued requiring changes in the accounting and disclosures for financial instruments. This standard was effective beginning with our 2018 reporting year and had no effect on our financial condition, results of operations or cash flows.

Accounting Pronouncements Not Yet Adopted

Leases

In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. In preparing for adoption, we have identified, reviewed and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired software and are implementing systems to facilitate lease capture and related accounting treatment.

Revenue Recognition, Policy

Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) it is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. Therefore, we bifurcate the consideration received between lease and service revenue. The service component is within the scope of Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09.

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Acquisitions (Tables)

6 Months Ended

Jun. 30, 2018

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following summarizes the value of assets and liabilities acquired:

	(in thousands)
Cash and cash equivalents	$	4,609
Accounts receivable	5,164
Prepaid and other current assets	8
Properties and equipment	275,061
Intangible assets	70,182
Goodwill	13,845
Accounts payable	(3,598		)
Accrued property taxes	(1,438		)
Net assets acquired	$	363,833

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Revenues (Tables)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Schedule of Cumulative Effect of Adjustment

The following table reflects the cumulative effect of adoption as of January 1, 2018:

	Prior to Adoption		Increase (Decrease)			As Adjusted
	(In millions)
Deferred revenue	$	9,598	$	(1,320	)	$	8,278
Partners’ equity: Common unitholders	$	393,959	$	1,320		$	395,279

Schedule of Contract Asset and Contract Liability Balances

	June 30, 2018			January 1, 2018
	(In thousands)
Contract asset	$	1,562		$	—
Contract liability	$	(4,441	)	$	(2,713	)

Schedule of Future Performance Obligations

We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and lease revenues):

Years Ending December 31,	(In millions)
Remainder of 2018	$	188
2019	352
2020	305
2021	294
2022	267
Thereafter	1,042
Total	$	2,448

Schedule of Disaggregated Revenue

Disaggregated revenues are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
Pipelines	$	65,539	$	55,248	$	137,708	$	107,695
Terminals, tanks and loading racks	34,386		36,356		72,567		70,163
Refinery processing units	18,835		17,539		37,369		36,919
	$	118,760	$	109,143	$	247,644	$	214,777

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Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Financial Instruments Measured on Recurring Basis

The carrying amounts and estimated fair values of our senior notes were as follows:

		June 30, 2018				December 31, 2017
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Liabilities:
6% Senior notes	Level 2	495,599		507,025		495,308		525,120
		$	495,599	$	507,025	$	495,308	$	525,120

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Properties and Equipment (Tables)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Schedule of Properties and Equipment

The carrying amounts of our properties and equipment are as follows:

	June 30, 2018		December 31, 2017
	(In thousands)
Pipelines, terminals and tankage	$	1,525,033	$	1,541,722
Refinery assets	347,338		347,338
Land and right of way	85,960		86,484
Construction in progress	42,811		12,029
Other	40,420		35,659
	2,041,562		2,023,232
Less accumulated depreciation	489,853		453,761
	$	1,551,709	$	1,569,471

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Intangible Assets (Tables)

6 Months Ended

Jun. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets by Major Class

The carrying amounts of our intangible assets are as follows:

	Useful Life	June 30, 2018		December 31, 2017
		(In thousands)
Delek transportation agreement	30 years	$	59,933	$	59,933
HFC transportation agreement	10-15 years	75,131		75,131
Customer relationships	10 years	69,282		69,282
Other		50		50
		204,396		204,396
Less accumulated amortization		82,461		74,933
		$	121,935	$	129,463

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Employees, Retirement and Incentive Plans (Tables)

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Nonvested Restricted Stock Units Activity

A summary of restricted and phantom unit activity and changes during the six months ended June 30, 2018, is presented below:

Restricted and Phantom Units	Units		Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2018 (nonvested)	119,009		$	34.77
Granted	12,890		30.23
Forfeited	(698	)	34.59
Outstanding at June 30, 2018 (nonvested)	131,201		$	34.33

Schedule of Nonvested Performance-based Units Activity

A summary of performance unit activity and changes for the six months ended June 30, 2018, is presented below:

Performance Units	Units
Outstanding at January 1, 2018 (nonvested)	36,911
Granted	2,764
Vesting and transfer of common units to recipients	(4,283	)
Outstanding at June 30, 2018 (nonvested)	35,392

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Debt (Tables)

6 Months Ended

Jun. 30, 2018

Debt Instruments [Abstract]

Schedule of Long-term Debt Instruments

The carrying amounts of our long-term debt are as follows:

	June 30, 2018			December 31, 2017
	(In thousands)
Credit Agreement
Amount outstanding	$	900,000		$	1,012,000
6% Senior Notes
Principal	500,000			500,000
Unamortized premium and debt issuance costs	(4,401		)	(4,692		)
	495,599			495,308
Total long-term debt	$	1,395,599		$	1,507,308

Schedule of Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Six Months Ended June 30,
	2018		2017
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	17,850	$	13,299
6.5% Senior Notes	—		162
6% Senior Notes	15,000		12,000
Amortization of discount and deferred debt issuance costs	1,516		1,536
Commitment fees and other	1,007		720
Total interest incurred	35,373		27,717
Less capitalized interest	166		430
Net interest expense	$	35,207	$	27,287
Cash paid for interest	$	33,935	$	33,700

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Significant Customers (Tables)

6 Months Ended

Jun. 30, 2018

Risks and Uncertainties [Abstract]

Schedules of Concentration of Risk, by Risk Factor

The following table presents the percentage of total revenues generated by each of these customers:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
HFC	79	%	85	%	79	%	85	%
Delek	7	%	6	%	6	%	7	%

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Partners' Equity, Income Allocations and Cash Distributions (Tables)

6 Months Ended

Jun. 30, 2018

Partners' Capital [Abstract]

Schedule of Allocation of General Partner Interest in Net Income

The following table presents the allocation of the general partner interest in net income for the periods presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
General partner interest in net income	$	—	$	827	$	—	$	1,338
General partner incentive distribution	—		17,501		—		34,128
Total general partner interest in net income	$	—	$	18,328	$	—	$	35,466

Schedule of Distributions Made to Limited Partners

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands, except per unit data)
General partner interest in distribution	$	—	$	1,188	$	—	$	2,336
General partner incentive distribution	—		17,501		—		34,128
Total general partner distribution	—		18,689		—		36,464
Limited partner distribution	67,091		40,682		133,670		80,314
Total regular quarterly cash distribution	$	67,091	$	59,371	$	133,670	$	116,778
Cash distribution per unit applicable to limited partners	$	0.6600	$	0.6325	$	1.3150	$	1.2525

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Net Income per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2018

Net Income per Limited Partner Unit [Abstract]

Schedule of Allocation to Limited Partner Interest in Net Income

For purposes of applying the two-class method, including the allocation of cash distributions in excess of earnings, net income per limited partner unit is computed as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Net income attributable to the partners	$	40,143		$	41,335		$	86,311		$	66,898
Less: General partner’s distribution declared (including IDRs)	—			(18,689		)	—			(36,464		)
Limited partner’s distribution declared on common units	(67,091		)	(40,682		)	(133,670		)	(80,314		)
Distributions in excess of net income attributable to the partners	$	(26,948	)	$	(18,036	)	$	(47,359	)	$	(49,880	)

Earnings per Unit by Type of Partner

	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Three Months Ended June 30, 2018
Net income attributable to the partners:
Distributions declared	$	—		$	67,091		$	67,091
Distributions in excess of net income attributable to the partners	—			(26,948		)	(26,948		)
Net income attributable to the partners	$	—		$	40,143		$	40,143
Weighted average limited partners' units outstanding				105,429
Limited partners' per unit interest in earnings - basic and diluted				$	0.38
Three Months Ended June 30, 2017
Net income attributable to the partners:
Distributions declared	$	18,689		$	40,682		$	59,371
Distributions in excess of net income attributable to the partners	(361		)	(17,675		)	(18,036		)
Net income attributable to the partners	$	18,328		$	23,007		$	41,335
Weighted average limited partners' units outstanding				64,086
Limited partners' per unit interest in earnings - basic and diluted				$	0.36

	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Six Months Ended June 30, 2018
Net income attributable to partnership:
Distributions declared	$	—		$	133,670		$	133,670
Distributions in excess of net income attributable to partnership	—			(47,359		)	(47,359		)
Net income attributable to partnership	$	—		$	86,311		$	86,311
Weighted average limited partners' units outstanding				104,637
Limited partners' per unit interest in earnings - basic and diluted				$	0.82
Six Months Ended June 30, 2017
Net income attributable to partnership:
Distributions declared	$	36,464		$	80,314		$	116,778
Distributions in excess of net income attributable to partnership	(998		)	(48,882		)	(49,880		)
Net income attributable to partnership	$	35,466		$	31,432		$	66,898
Weighted average limited partners' units outstanding				63,602
Limited partners' per unit interest in earnings - basic and diluted				$	0.49

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Operating Segments (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Pipelines and terminals - affiliate	$	75,178		$	75,613		$	158,072		$	145,258
Pipelines and terminals - third-party	24,747			15,991			52,203			32,600
Refinery processing units - affiliate	18,835			17,539			37,369			36,919
Total segment revenues	$	118,760		$	109,143		$	247,644		$	214,777
Segment operating income:
Pipelines and terminals	$	51,004		$	49,164		$	111,217		$	95,649
Refinery processing units	8,615			5,937			15,942			13,820
Total segment operating income	59,619			55,101			127,159			109,469
Unallocated general and administrative expenses	(2,673		)	(2,615		)	(5,795		)	(5,249		)
Interest and financing costs, net	(17,100		)	(13,645		)	(34,166		)	(39,307		)
Equity in earnings of unconsolidated affiliates	1,734			4,053			3,013			5,893
Gain (loss) on sale of assets and other	(53		)	89			33			162
Income before income taxes	$	41,527		$	42,983		$	90,244		$	70,968
Capital Expenditures:
Pipelines and terminals	$	12,127		$	12,157		$	24,739		$	20,286
Refinery processing units	—			102			—			238
Total capital expenditures	$	12,127		$	12,259		$	24,739		$	20,524

	June 30, 2018		December 31, 2017
	(in thousands)
Identifiable assets:
Pipelines and terminals (1)	$	1,697,531	$	1,728,074
Refinery processing units	321,191		328,585
Other	97,341		97,455
Total identifiable assets	$	2,116,063	$	2,154,114

(1) Includes goodwill of $270.3 million and $266.7 million as of June 30, 2018 and December 31, 2017, respectively.

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Supplemental Guarantor / Non-Guarantor Financial Information (Tables)

6 Months Ended

Jun. 30, 2018

Supplemental Guarantor / Non-Guarantor Financial Information [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet

June 30, 2018	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	640	$	6,014	$	—		$	6,656
Accounts receivable	—		45,447		5,305		(586		)	50,166
Prepaid and other current assets	156		2,629		361		—			3,146
Total current assets	158		48,716		11,680		(586		)	59,968
Properties and equipment, net	—		1,197,968		353,741		—			1,551,709
Investment in subsidiaries	1,866,892		269,911		—		(2,136,803		)	—
Intangible assets, net	—		121,935		—		—			121,935
Goodwill	—		270,336		—		—			270,336
Equity method investments	—		84,752		—		—			84,752
Other assets	10,483		16,880		—		—			27,363
Total assets	$	1,877,533	$	2,010,498	$	365,421	$	(2,137,389	)	$	2,116,063
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	19,284	$	1,700	$	(586	)	$	20,398
Accrued interest	13,189		—		—		—			13,189
Deferred revenue	—		9,675		1,170		—			10,845
Accrued property taxes	—		3,077		2,463		—			5,540
Other current liabilities	88		3,505		—		—			3,593
Total current liabilities	13,277		35,541		5,333		(586		)	53,565
Long-term debt	1,395,599		—		—		—			1,395,599
Other long-term liabilities	260		15,060		206		—			15,526
Deferred revenue	—		48,405		—		—			48,405
Class B unit	—		44,600		—		—			44,600
Equity - partners	468,397		1,866,892		269,911		(2,136,803		)	468,397
Equity - noncontrolling interest	—		—		89,971		—			89,971
Total liabilities and equity	$	1,877,533	$	2,010,498	$	365,421	$	(2,137,389	)	$	2,116,063

Condensed Consolidating Balance Sheet

December 31, 2017	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	511	$	7,263	$	—		$	7,776
Accounts receivable	—		59,448		5,038		(182		)	64,304
Prepaid and other current assets	13		2,016		282		—			2,311
Total current assets	15		61,975		12,583		(182		)	74,391
Properties and equipment, net	—		1,213,626		355,845		—			1,569,471
Investment in subsidiaries	1,902,285		273,319		—		(2,175,604		)	—
Intangible assets, net	—		129,463		—		—			129,463
Goodwill	—		266,716		—		—			266,716
Equity method investments	—		85,279		—		—			85,279
Other assets	11,753		17,041		—		—			28,794
Total assets	$	1,914,053	$	2,047,419	$	368,428	$	(2,175,786	)	$	2,154,114
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	20,928	$	1,526	$	(182	)	$	22,272
Accrued interest	12,500		756		—		—			13,256
Deferred revenue	—		8,540		1,058		—			9,598
Accrued property taxes	—		3,431		1,221		—			4,652
Other current liabilities	—		5,707		—		—			5,707
Total current liabilities	12,500		39,362		3,805		(182		)	55,485
Long-term debt	1,507,308		—		—		—			1,507,308
Other long-term liabilities	286		15,359		198		—			15,843
Deferred revenue	—		47,272		—		—			47,272
Class B unit	—		43,141		—		—			43,141
Equity - partners	393,959		1,902,285		273,319		(2,175,604		)	393,959
Equity - noncontrolling interest	—		—		91,106		—			91,106
Total liabilities and equity	$	1,914,053	$	2,047,419	$	368,428	$	(2,175,786	)	$	2,154,114

Condensed Consolidating Statement of Comprehensive Income

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	89,522		$	4,491		$	—		$	94,013
Third parties	—			19,540			5,207			—			24,747
	—			109,062			9,698			—			118,760
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			31,494			3,039			—			34,533
Depreciation and amortization				20,431			4,177			—			24,608
General and administrative	761			1,912			—			—			2,673
	761			53,837			7,216			—			61,814
Operating income (loss)	(761		)	55,225			2,482			—			56,946
Other income (expense):
Equity in earnings of subsidiaries	58,566			1,881			—			(60,447		)	—
Equity in earnings of equity method investments	—			1,734			—			—			1,734
Interest expense	(17,662		)	36			—			—			(17,626		)
Interest income	—			526			—			—			526
Gain on sale of assets and other	—			(79		)	26			—			(53		)
	40,904			4,098			26			(60,447		)	(15,419		)
Income before income taxes	40,143			59,323			2,508			(60,447		)	41,527
State income tax expense	—			(28		)	—			—			(28		)
Net income	40,143			59,295			2,508			(60,447		)	41,499
Allocation of net income attributable to noncontrolling interests	—			(729		)	(627		)	—			(1,356		)
Net income attributable to the partners	40,143			58,566			1,881			(60,447		)	40,143
Other comprehensive income	—			—			—			—			—
Comprehensive income attributable to the partners	$	40,143		$	58,566		$	1,881		$	(60,447	)	$	40,143

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	88,022		$	5,130		$	—		$	93,152
Third parties	—			10,385			5,606			—			15,991
	—			98,407			10,736			—			109,143
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			30,871			3,226			—			34,097
Depreciation and amortization	—			15,791			4,154			—			19,945
General and administrative	865			1,750			—			—			2,615
	865			48,412			7,380			—			56,657
Operating income (loss)	(865		)	49,995			3,356			—			52,486
Other income (expense):
Equity in earnings of subsidiaries	48,375			2,519			—			(50,894		)	—
Equity in earnings of equity method investments	—			4,053			—			—			4,053
Interest expense	(6,175		)	(7,573		)	—			—			(13,748		)
Interest income	—			103			—			—			103
Gain on sale of assets and other	—			87			2			—			89
	42,200			(811		)	2			(50,894		)	(9,503		)
Income before income taxes	41,335			49,184			3,358			(50,894		)	42,983
State income tax expense	—			(127		)	—			—			(127		)
Net income	41,335			49,057			3,358			(50,894		)	42,856
Allocation of net income attributable to noncontrolling interests	—			(682		)	(839		)	—			(1,521		)
Net income attributable to the partners	41,335			48,375			2,519			(50,894		)	41,335
Other comprehensive income	(91		)	(91		)	—			91			(91		)
Comprehensive income attributable to the partners	$	41,244		$	48,284		$	2,519		$	(50,803	)	$	41,244

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	183,813		$	11,628		$	—		$	195,441
Third parties	—			39,518			12,685			—			52,203
	—			223,331			24,313			—			247,644
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			64,158			6,577			—			70,735
Depreciation and amortization	—			41,432			8,318			—			49,750
General and administrative	2,041			3,754			—			—			5,795
	2,041			109,344			14,895			—			126,280
Operating income (loss)	(2,041		)	113,987			9,418			—			121,364
Other income (expense):
Equity in earnings (loss) of subsidiaries	123,618			7,093			—			(130,711		)	—
Equity in earnings of equity method investments	—			3,013			—			—			3,013
Interest expense	(35,311		)	104			—			—			(35,207		)
Interest income	—			1,041			—			—			1,041
Gain (loss) on sale of assets and other	45			(51		)	39			—			33
	88,352			11,200			39			(130,711		)	(31,120		)
Income (loss) before income taxes	86,311			125,187			9,457			(130,711		)	90,244
State income tax expense	—			(110		)	—			—			(110		)
Net income (loss)	86,311			125,077			9,457			(130,711		)	90,134
Allocation of net income attributable to noncontrolling interests	—			(1,459		)	(2,364		)	—			(3,823		)
Net income (loss) attributable to Holly Energy Partners	86,311			123,618			7,093			(130,711		)	86,311
Other comprehensive income (loss)	—			—			—			—			—
Comprehensive income (loss)	$	86,311		$	123,618		$	7,093		$	(130,711	)	$	86,311

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	168,798		$	13,379		$	—		$	182,177
Third parties	—			21,388			11,212			—			32,600
	—			190,186			24,591			—			214,777
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			59,963			6,623			—			66,586
Depreciation and amortization	—			30,644			8,078			—			38,722
General and administrative	2,020			3,229			—			—			5,249
	2,020			93,836			14,701			—			110,557
Operating income (loss)	(2,020		)	96,350			9,890			—			104,220
Other income (expense):
Equity in earnings (loss) of subsidiaries	93,658			7,420			—			(101,078		)	—
Equity in earnings of equity method investments	—			5,893			—			—			5,893
Interest expense	(12,515		)	(14,772		)	—			—			(27,287		)
Interest income	—			205			—			—			205
Loss on early extinguishment of debt	(12,225		)	—			—			—			(12,225		)
Gain (loss) on sale of assets and other	—			159			3			—			162
	68,918			(1,095		)	3			(101,078		)	(33,252		)
Income (loss) before income taxes	66,898			95,255			9,893			(101,078		)	70,968
State income tax expense	—			(233		)	—			—			(233		)
Net income (loss)	66,898			95,022			9,893			(101,078		)	70,735
Allocation of net income attributable to noncontrolling interests	—			(1,364		)	(2,473		)	—			(3,837		)
Net income (loss) attributable to Holly Energy Partners	66,898			93,658			7,420			(101,078		)	66,898
Other comprehensive income (loss)	(28		)	(28		)	—			28			(28		)
Comprehensive income (loss)	$	66,870		$	93,630		$	7,420		$	(101,050	)	$	66,870

Condensed Consolidating Statement of Cash Flows

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2018	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(33,588	)	$	182,983		$	18,661		$	(7,093	)	$	160,963
Cash flows from investing activities
Additions to properties and equipment	—			(18,829		)	(5,910		)	—			(24,739		)
Business and asset acquisitions	—			(6,831		)	—			—			(6,831		)
Distributions from UNEV in excess of earnings	—			3,407			—			(3,407		)	—
Proceeds from sale of assets	—			196			—			—			196
Distributions in excess of equity in earnings of equity investments	—			299			—			—			299
	—			(21,758		)	(5,910		)	(3,407		)	(31,075		)
Cash flows from financing activities
Net repayments under credit agreement	(112,000		)	—			—			—			(112,000		)
Net intercompany financing activities	160,330			(160,330		)	—			—			—
Proceeds from issuance of common units	114,899			(68		)	—			—			114,831
Contribution from general partner	492			—			—			—			492
Distributions to HEP unitholders	(130,075		)	—			—			—			(130,075		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Units withheld for tax withholding obligations	(58		)	—			—			—			(58		)
Other	—			(698		)	—			—			(698		)
	33,588			(161,096		)	(14,000		)	10,500			(131,008		)
Cash and cash equivalents
Increase (decrease) for the period	—			129			(1,249		)	—			(1,120		)
Beginning of period	2			511			7,263			—			7,776
End of period	$	2		$	640		$	6,014		$	—		$	6,656

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(20,377	)	$	122,025		$	19,373		$	(7,420	)	$	113,601
Cash flows from investing activities
Additions to properties and equipment	—			(17,670		)	(2,854		)	—			(20,524		)
Proceeds from sale of assets	—			635			—			—			635
Distributions from UNEV in excess of earnings	—			3,080			—			(3,080		)	—
Distributions in excess of equity in earnings of equity investments	—			1,654			—			—			1,654
	—			(12,301		)	(2,854		)	(3,080		)	(18,235		)
Cash flows from financing activities
Net borrowings under credit agreement	—			290,000			—			—			290,000
Net intercompany financing activities	389,005			(389,005		)	—			—			—
Redemption of senior notes	(309,750		)	—			—			—			(309,750		)
Proceeds from issuance of common units	52,383			251			—			—			52,634
Distributions to HEP unitholders	(112,195		)	—			—			—			(112,195		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Distribution to HFC for El Dorado tanks	(103		)	—			—			—			(103		)
Contributions from general partner	1,072			(77		)	—			—			995
Units withheld for tax withholding obligations	(35		)	—			—			—			(35		)
Other	—			(730		)	—			—			(730		)
	20,377			(99,561		)	(14,000		)	10,500			(82,684		)
Cash and cash equivalents
Decrease for the period	—			10,163			2,519			—			12,682
Beginning of period	2			301			3,354			—			3,657
End of period	$	2		$	10,464		$	5,873		$	—		$	16,339

XML

Description of Business and Presentation of Financial Statements - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Oct. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Other Ownership Interests [Line Items]
Ownership percentage, controlling interest		57.00%		57.00%
General partner interest	2.00%
Common unit, issued (in shares)	37,250,000
Limited partner distribution	$ 2,500	$ 67,091	$ 40,682	$ 133,670	$ 80,314
Partners' capital account, units, sold in private placement (in shares)		3,700,000
Sale of stock, price per share (in dollars per share)		$ 29.73		$ 29.73
Proceeds from issuance of private placement		$ 110,000
SLC Pipeline
Other Ownership Interests [Line Items]
Equity method investment, ownership percentage						75.00%
UNEV Pipeline
Other Ownership Interests [Line Items]
Equity method investment, ownership percentage		75.00%		75.00%
Frontier Pipeline
Other Ownership Interests [Line Items]
Equity method investment, ownership percentage		50.00%		50.00%		50.00%

XML

Acquisitions - Narrative and Summary of Acquired Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2017	Jun. 30, 2018	Oct. 31, 2017
Business Acquisition [Line Items]
Purchase price			$ 250,000
Step Acquisition, Equity Interest in Acquiree	$ 112,000
Step Acquisition - Remeasurement Gain	36,300
Consideration Transferred	$ 363,800
Working Capital Adjustment		$ 1,800
Assets Acquired - Cash and Equivalents			4,609
Assets Acquired - Receivables			5,164
Assets Acquired - Prepaid and other Current Assets			8
Assets Acquired - Properties and Equipment			275,061
Assets Acquired - Intangible Assets			70,182
Goodwill			13,845
Liabilities Assumed - Accounts Payable			(3,598)
Liabilities Assumed - Accrued Property Taxes			(1,438)
Net Assets Acquired			$ 363,833
SLC Pipeline
Business Acquisition [Line Items]
Equity method investment, ownership percentage	75.00%
Frontier Pipeline
Business Acquisition [Line Items]
Equity method investment, ownership percentage	50.00%	50.00%

XML

Revenues - Schedule of Cumulative Effect of Adjustment (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Jan. 01, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenue	$ 10,845	$ 8,278	$ 9,598
Partners’ equity: Common unitholders	$ 468,397	395,279	393,959
Prior to Adoption
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenue			9,598
Partners’ equity: Common unitholders			$ 393,959
Increase (Decrease) | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenue		(1,320)
Partners’ equity: Common unitholders		$ 1,320

XML

Revenues - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Lease Income	$ 68,100	$ 138,700
Recognition of Deferred Revenue	3,400	7,000
Deferred revenue, recognized	400	2,600
Deferred Revenue, Period Increase (Decrease)		4,400
Deferred revenue	48,405	48,405	$ 47,272
Sales Revenue, Services, Other	$ 50,700	$ 109,000

XML

Revenues - Narrative, Remaining Performance Obligation (Details) $ in Millions	Jun. 30, 2018 USD ($) yr
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 188
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	352
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	305
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	294
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	267
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	1,042
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 2,448
Maximum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue service commitments expiration | yr	2,036
Minimum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue service commitments expiration | yr	2,019

XML

Revenues - Schedule of Future Performance Obligations (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 188
Unfulfilled performance obligations, expected timing	6 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 352
Unfulfilled performance obligations, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 305
Unfulfilled performance obligations, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 294
Unfulfilled performance obligations, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 267
Unfulfilled performance obligations, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unfulfilled performance obligations	$ 2,448
Unfulfilled performance obligations, expected timing

XML

Revenues - Schedule of Contract Asset and Liability Balances (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Contract asset	$ 1,562	$ 0
Contract liability	$ (4,441)	$ (2,713)

XML

Revenues - Schedule of Disaggregated Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Disaggregated Revenue	$ 118,760	$ 109,143	$ 247,644	$ 214,777
Pipelines
Disaggregation of Revenue [Line Items]
Disaggregated Revenue	65,539	55,248	137,708	107,695
Terminals, tanks and loading racks
Disaggregation of Revenue [Line Items]
Disaggregated Revenue	34,386	36,356	72,567	70,163
Refinery processing units
Disaggregation of Revenue [Line Items]
Disaggregated Revenue	$ 18,835	$ 17,539	$ 37,369	$ 36,919

XML

Financial Instruments - Narrative (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Senior Notes	$ 100,000
6% Senior notes
Debt Instrument [Line Items]
Senior Notes		$ 495,308
Carrying Value
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	495,599	495,308
Carrying Value | 6% Senior notes
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure		495,308
Senior Notes	495,599
Fair Value | Fair value inputs, Level 2
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	507,025	525,120
Fair Value | 6% Senior notes | Fair value inputs, Level 2
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	$ 507,025	$ 525,120

XML

Properties and Equipment - Schedule of Properties and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	$ 2,041,562	$ 2,023,232
Less accumulated depreciation	489,853	453,761
Properties and equipment, net	1,551,709	1,569,471
Pipelines, terminals and tankage
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	1,525,033	1,541,722
Refinery Assets
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	347,338	347,338
Land and right of way
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	85,960	86,484
Construction in progress
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	42,811	12,029
Other
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	$ 40,420	$ 35,659

XML

Properties and Equipment - Narrative (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Property, Plant and Equipment [Abstract]
Interest costs, capitalized during period	$ 166	$ 430
Depreciation expense	$ 41,900	$ 34,900

XML

Intangible Assets - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, gross	$ 204,396	$ 204,396
Less accumulated amortization	82,461	74,933
Intangible assets, net	121,935	129,463
Delek transportation agreement
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, gross	$ 59,933	59,933
Useful Life	30 years
HFC transportation agreement
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, gross	$ 75,131	75,131
Customer relationships
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, gross	$ 69,282	69,282
Useful Life	10 years
Other
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, gross	$ 50	$ 50
Minimum | HFC transportation agreement
Finite-Lived Intangible Assets, Net [Abstract]
Useful Life	10 years
Maximum | HFC transportation agreement
Finite-Lived Intangible Assets, Net [Abstract]
Useful Life	15 years

XML

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 7.5	$ 3.5
Estimated amortization expense, remainder of fiscal year	14.0
Estimated amortization expense, 2019	14.0
Estimated amortization expense, 2020	14.0
Estimated amortization expense, 2021	14.0
Estimated amortization expense, 2022	14.0
Estimated amortization expense, 2023	$ 9.8

XML

Employees, Retirement and Incentive Plans Retirement and Benefit Plan Costs (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($) shares	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) Components shares	Jun. 30, 2017 USD ($)
Share-based Compensation Arrangements
Employee benefits and share-based compensation | $	$ 1.6	$ 1.3	$ 3.4	$ 3.0
Long-term Incentive Plan, Components | Components			4
Number of incentive-based award plans	2		2
Compensation costs of incentive awards | $	$ 0.7	$ 0.6	$ 1.5	$ 0.9
Deferred Bonus
Share-based Compensation Arrangements
Units authorized under equity-based compensation plans (new) | shares	2,500,000		2,500,000
Number of units available for grant | shares	1,323,787		1,323,787

XML

Employees, Retirement and Incentive Plans Restricted Units (Details) - USD ($) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Restricted and Phantom Units
Share-based Compensation Arrangements
Nonvested restricted units outstanding	131,201	119,009
Weighted average grant date fair value	$ 34.33	$ 34.77
Granted	12,890
Weighted Average Grant Date Fair Value	$ 30.23
Total unrecognized compensation related to nonvested units	$ 1.8
Weighted average remaining contractual term (years)	1 year 2 months
Forfeitures	(698)
Weighted Average Grant Date Fair Value - Forfeitures	$ 34.59
Performance Shares [Member]
Share-based Compensation Arrangements
Nonvested restricted units outstanding	35,392	36,911
Granted	2,764
Total unrecognized compensation related to nonvested units	$ 0.7
Weighted average remaining contractual term (years)	1 year 7 months
Maximum | Restricted Stock [Member]
Share-based Compensation Arrangements
Award Vesting Period	3 years

XML

Employees, Retirement and Incentive Plans Performance Units (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($) shares
Share-based Compensation Arrangement Instruments [Roll Forward]
Weighted Average Fair Value of Units Outstanding | $	$ 1.2
Performance Shares [Member]
Share-based Compensation Arrangements
Estimated Share Payouts Unit Awards Minimum	100.00%
Estimated Share Payouts Unit Awards Maximum	150.00%
Share-based Compensation Arrangement Instruments [Roll Forward]
Outstanding at January 1, 2018 (nonvested)	36,911
Granted	2,764
Vesting and transfer of common units to recipients	(4,283)
Outstanding at June 30, 2018 (nonvested)	35,392
Fair value of vested units transferred to recipients | $	$ 0.1
Total unrecognized compensation related to nonvested units | $	$ 0.7
Weighted average remaining contractual term (years)	1 year 7 months
Restricted and Phantom Units
Share-based Compensation Arrangement Instruments [Roll Forward]
Outstanding at January 1, 2018 (nonvested)	119,009
Granted	12,890
Outstanding at June 30, 2018 (nonvested)	131,201
Total unrecognized compensation related to nonvested units | $	$ 1.8
Weighted average remaining contractual term (years)	1 year 2 months
Executive Officer [Member] | Performance Shares [Member]
Share-based Compensation Arrangements
Estimated Share Payouts Unit Awards Minimum	50.00%
Estimated Share Payouts Unit Awards Maximum	150.00%

XML

Debt - Senior Notes (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Jan. 04, 2017
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,400,000		$ 1,400,000
Line of Credit Facility, Expiration Date		Jul. 01, 2022
Line of Credit Facility, Capacity Available for Trade Purchases		$ 50,000		50,000
Line of Credit Facility, Accordion Feature		300,000		300,000
Senior Notes		100,000		100,000
Loss on early extinguishment of debt		$ 0	$ 0	$ 0	$ (12,225)
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Principal							$ 300,000
Stated interest rate, senior notes		6.50%		6.50%			6.50%
Senior Notes Aggregate Redemption Amount							$ 309,800
Loss on early extinguishment of debt	$ 12,200
Unamortized Premium	9,800
Unamortized Discount	$ 2,400
6% Senior notes
Debt Instrument [Line Items]
Principal		$ 500,000	$ 400,000	$ 500,000	$ 400,000	$ 500,000
Senior Notes						$ 495,308
Stated interest rate, senior notes		6.00%		6.00%

XML

Debt Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Jan. 04, 2017
Debt Instrument [Line Items]
Credit Agreement	$ 900,000	$ 1,012,000
Senior Notes	100,000
Total long-term debt	1,395,599	1,507,308
6% Senior notes
Debt Instrument [Line Items]
Principal	500,000	500,000	$ 400,000
Unamortized discount	$ (4,401)	(4,692)
Senior Notes		$ 495,308
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Principal				$ 300,000

XML

Debt - Interest Rate Risk Management (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 900,000	$ 1,012,000
London Interbank Offered Rate (LIBOR) [Member] | Interest Rate Swap [Member] | Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 150,000	$ 0

XML

Debt - Interest Expense and Other Debt Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Debt Instrument [Line Items]
Interest expense, debt			$ 35,373	$ 27,717
Less capitalized interest			166	430
Interest expense	$ 17,626	$ 13,748	35,207	27,287
Cash paid for interest			33,935	33,700
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Interest expense, debt			17,850	13,299
Senior Notes [Member] | 6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt			0	162
Senior Notes [Member] | 6% Senior notes
Debt Instrument [Line Items]
Interest expense, debt			15,000	12,000
Amortization discount and deferred debt issuance costs [Member]
Debt Instrument [Line Items]
Interest expense, debt			1,516	1,536
Commitment Fees and Other [Member]
Debt Instrument [Line Items]
Interest expense, debt			$ 1,007	$ 720

XML

Debt Debt - Capital Leases (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Capital Leased Assets [Line Items]
Capital Leased Assets, Gross	$ 5.7	$ 5.1
Capital Leases Accumulated Depreciation	$ 3.7	$ 3.3
Minimum
Capital Leased Assets [Line Items]
Capital Leases, Term of Contract	33 months
Maximum
Capital Leased Assets [Line Items]
Capital Leases, Term of Contract	48 months

XML

Significant Customers - Narrative and Schedule of Percentage of Total Revenues By Customer (Details) - Sales Revenue, Net - Customers	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenue, Major Customer [Line Items]
Concentration risk, percentage of total sales			86.00%
Concentration risk, number of significant customers			2
HFC
Revenue, Major Customer [Line Items]
Concentration risk, percentage of total sales	79.00%	85.00%	79.00%	85.00%
Delek
Revenue, Major Customer [Line Items]
Concentration risk, percentage of total sales	7.00%	6.00%	6.00%	7.00%

XML

Related Party Transactions - Narrative (Details) $ in Thousands	1 Months Ended	3 Months Ended			6 Months Ended
	Oct. 31, 2017 USD ($) shares	Jun. 30, 2018 USD ($) yr	Dec. 31, 2017 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) yr	Jun. 30, 2017 USD ($)
Related Party Transaction [Line Items]
Administrative fee, related party					$ 2,500
Revenue from related parties		$ 94,013		$ 93,152	195,441	$ 182,177
Omnibus Agreement G & A expenses, related party		600			1,200
Employee expenses reimbursed to related party		12,500		11,400	25,200	22,900
Reimbursements received from related parties		2,900		1,500	4,200	2,800
Accounts receivable due from HFC		36,700	$ 51,500		36,700
Due to Affiliate		11,300			11,300
Accounts payable to HFC		11,250	7,725		11,250
Lease Income		500		100	1,000	200
General partner interest	2.00%
Common unit, issued (in shares) | shares	37,250,000
Limited partner distribution	$ 2,500	67,091		40,682	133,670	80,314
Affiliated Entity
Related Party Transaction [Line Items]
Minimum annualized payments		334,500			334,500
Distributions to HEP unitholders		$ 36,600		$ 32,600	72,800	$ 63,900
Shortfall Payments
Related Party Transaction [Line Items]
Shortfall billings deferred revenue			$ 4,400		$ 1,700
Minimum
Related Party Transaction [Line Items]
Revenue service commitments expiration | yr		2,019			2,019
Maximum
Related Party Transaction [Line Items]
Revenue service commitments expiration | yr		2,036			2,036

XML

Partners' Equity, Income Allocations and Cash Distributions - Issuances (Details) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended	26 Months Ended
	Jun. 30, 2018 USD ($) $ / shares shares	Jun. 30, 2018 USD ($) $ / shares shares	Jun. 30, 2018 USD ($) $ / shares shares
Partners' Capital [Abstract]
Common units held by HFC (in shares) | shares	59,630,030	59,630,030	59,630,030
Ownership percentage, controlling interest	57.00%	57.00%	57.00%
Partners' capital account, units, sold in private placement (in shares) | shares	3,700,000
Sale of stock, price per share (in dollars per share) | $ / shares	$ 29.73	$ 29.73	$ 29.73
Proceeds from issuance of private placement | $	$ 110.0
Common Unit Issuance Program | $		$ 200.0
Partners' capital account, units, sale of units (in shares) | shares		171,246	2,413,153
Gross proceeds from issuance of common units | $		$ 5.2	$ 82.3

XML

Partners' Equity, Income Allocations and Cash Distributions - Allocations of Net Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Partners' Capital [Abstract]
General partner interest in net income	$ 0	$ 827	$ 0	$ 1,338
General partner incentive distribution	0	17,501	0	34,128
Total general partner interest in net income	$ 0	$ 18,328	$ 0	$ 35,466

XML

Partners' Equity, Income Allocations and Cash Distributions - Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands				1 Months Ended	3 Months Ended		6 Months Ended
	Aug. 09, 2018	Jul. 30, 2018	Jul. 19, 2018	Oct. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Distribution Payments [Line Items]
Limited partner distribution				$ 2,500	$ 67,091	$ 40,682	$ 133,670	$ 80,314
Partner Distributions
General partner interest in distribution					0	1,188	0	2,336
General partner incentive distribution					0	17,501	0	34,128
Total general partner distribution					0	18,689	0	36,464
Limited partner distribution				$ 2,500	67,091	40,682	133,670	80,314
Total regular quarterly cash distributions					$ 67,091	$ 59,371	$ 133,670	$ 116,778
Cash distribution per unit applicable to limited partners (in dollars per share)					$ 0.6600	$ 0.6325	$ 1.3150	$ 1.2525
Subsequent Event
Distribution Payments [Line Items]
Dividends payable, date declared			Jul. 19, 2018
Partners' capital, distribution amount per share (in dollars per share)			$ 0.66
Dividends payable, date to be paid	Aug. 09, 2018
Dividends payable, date of record		Jul. 30, 2018
Limited partner distribution	$ 2,500
Partner Distributions
Limited partner distribution	$ 2,500

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Net Income per Limited Partner Unit - Schedules of Computations (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Oct. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings per Unit by Type of Partner [Line Items]
Net income attributable to the partners		$ 40,143	$ 41,335	$ 86,311	$ 66,898
General Partners' Distribution Declared		0	(18,689)	0	(36,464)
Limited partner distribution declared	$ 2,500	67,091	40,682	133,670	80,314
Distributions in excess of net income attributable to the partners		(26,948)	(18,036)	(47,359)	(49,880)
Net income attributable to partnership		40,143	41,335	86,311	66,898
Total partner interest in net income		$ 67,091	$ 59,371	$ 133,670	$ 116,778
Weighted average limited partners’ units outstanding		105,429	64,086	104,637	63,602
Limited partners’ per unit interest in earnings—basic and diluted:		$ 0.38	$ 0.36	$ 0.82	$ 0.49
General Partner
Earnings per Unit by Type of Partner [Line Items]
Distributions in excess of net income attributable to the partners		$ 0	$ (361)	$ 0	$ (998)
Net income attributable to partnership		0	18,328	0	35,466
Limited Partner
Earnings per Unit by Type of Partner [Line Items]
Distributions in excess of net income attributable to the partners		(26,948)	(17,675)	(47,359)	(48,882)
Net income attributable to partnership		$ 40,143	$ 23,007	$ 86,311	$ 31,432

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Environmental Environmental (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Loss Contingencies [Line Items]
Environmental remediation expense	$ 300,000	$ 0	$ 0	$ 0
Accrued environmental expense	6,300,000		6,300,000		$ 6,500,000
Accrued environmental expense, noncurrent	4,700,000		4,700,000		5,000,000
Affiliated Entity
Loss Contingencies [Line Items]
Accrued environmental expense	$ 700,000		$ 700,000		$ 800,000

XML

Operating Segments - Schedule of Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues		$ 118,760	$ 109,143	$ 247,644	$ 214,777
Operating Income (Loss)		56,946	52,486	121,364	104,220
Segment operating profit		59,619	55,101	127,159	109,469
Unallocated general and administrative		(2,673)	(2,615)	(5,795)	(5,249)
Interest and financing costs, net		(17,100)	(13,645)	(34,166)	(39,307)
Equity in earnings of unconsolidated affiliates		1,734	4,053	3,013	5,893
Gain (loss) on sale of assets and other		(53)	89	33	162
Income before income taxes		41,527	42,983	90,244	70,968
Capital Expenditures		12,127	12,259	24,739	20,524
Assets		2,116,063		2,116,063		$ 2,154,114
Goodwill		270,336		270,336		266,716
Pipelines and terminal - affiliate
Segment Reporting Information [Line Items]
Revenues		75,178	75,613	158,072	145,258
Pipelines and terminals - third party
Segment Reporting Information [Line Items]
Revenues		24,747	15,991	52,203	32,600
Operating Income (Loss)		51,004	49,164	111,217	95,649
Capital Expenditures		12,127	12,157	24,739	20,286
Assets	[1]	1,697,531		1,697,531		1,728,074
Refinery processing units
Segment Reporting Information [Line Items]
Revenues		18,835	17,539	37,369	36,919
Operating Income (Loss)		8,615	5,937	15,942	13,820
Capital Expenditures		0	$ 102	0	$ 238
Assets		321,191		321,191		328,585
Other
Segment Reporting Information [Line Items]
Assets		$ 97,341		$ 97,341		$ 97,455

[1] Includes goodwill of $270.3 million and $266.7 million as of June 30, 2018 and December 31, 2017, respectively.

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Jan. 01, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 6,656		$ 7,776	$ 16,339	$ 3,657
Accounts receivable	50,166		64,304
Prepaid and other current assets	3,146		2,311
Total current assets	59,968		74,391
Properties and equipment, net	1,551,709		1,569,471
Investment in subsidiaries	0		0
Intangible assets, net	121,935		129,463
Goodwill	270,336		266,716
Equity method investments	84,752		85,279
Other assets	27,363		28,794
Assets	2,116,063		2,154,114
Current liabilities:
Accounts payable	20,398		22,272
Accrued interest	13,189		13,256
Deferred revenue	10,845	$ 8,278	9,598
Accrued property taxes	5,540		4,652
Other current liabilities	3,593		5,707
Total current liabilities	53,565		55,485
Long-term debt	1,395,599		1,507,308
Other long-term liabilities	15,526		15,843
Deferred revenue	48,405		47,272
Class B unit	44,600		43,141
Equity - partners	468,397		393,959
Equity - noncontrolling interest	89,971		91,106
Total liabilities and equity	2,116,063		2,154,114
Parent
Current assets:
Cash and cash equivalents	2		2	2	2
Accounts receivable	0		0
Prepaid and other current assets	156		13
Total current assets	158		15
Properties and equipment, net	0		0
Investment in subsidiaries	1,866,892		1,902,285
Intangible assets, net	0		0
Goodwill	0		0
Equity method investments	0		0
Other assets	10,483		11,753
Assets	1,877,533		1,914,053
Current liabilities:
Accounts payable	0		0
Accrued interest	13,189		12,500
Deferred revenue	0		0
Accrued property taxes	0		0
Other current liabilities	88		0
Total current liabilities	13,277		12,500
Long-term debt	1,395,599		1,507,308
Other long-term liabilities	260		286
Deferred revenue	0		0
Class B unit	0		0
Equity - partners	468,397		393,959
Equity - noncontrolling interest	0		0
Total liabilities and equity	1,877,533		1,914,053
Guarantor Restricted Subsidiaries
Current assets:
Cash and cash equivalents	640		511	10,464	301
Accounts receivable	45,447		59,448
Prepaid and other current assets	2,629		2,016
Total current assets	48,716		61,975
Properties and equipment, net	1,197,968		1,213,626
Investment in subsidiaries	269,911		273,319
Intangible assets, net	121,935		129,463
Goodwill	270,336		266,716
Equity method investments	84,752		85,279
Other assets	16,880		17,041
Assets	2,010,498		2,047,419
Current liabilities:
Accounts payable	19,284		20,928
Accrued interest	0		756
Deferred revenue	9,675		8,540
Accrued property taxes	3,077		3,431
Other current liabilities	3,505		5,707
Total current liabilities	35,541		39,362
Long-term debt	0		0
Other long-term liabilities	15,060		15,359
Deferred revenue	48,405		47,272
Class B unit	44,600		43,141
Equity - partners	1,866,892		1,902,285
Equity - noncontrolling interest	0		0
Total liabilities and equity	2,010,498		2,047,419
Non-Guarantor Non-Restricted Subsidiaries
Current assets:
Cash and cash equivalents	6,014		7,263	5,873	3,354
Accounts receivable	5,305		5,038
Prepaid and other current assets	361		282
Total current assets	11,680		12,583
Properties and equipment, net	353,741		355,845
Investment in subsidiaries	0		0
Intangible assets, net	0		0
Goodwill	0		0
Equity method investments	0		0
Other assets	0		0
Assets	365,421		368,428
Current liabilities:
Accounts payable	1,700		1,526
Accrued interest	0		0
Deferred revenue	1,170		1,058
Accrued property taxes	2,463		1,221
Other current liabilities	0		0
Total current liabilities	5,333		3,805
Long-term debt	0		0
Other long-term liabilities	206		198
Deferred revenue	0		0
Class B unit	0		0
Equity - partners	269,911		273,319
Equity - noncontrolling interest	89,971		91,106
Total liabilities and equity	365,421		368,428
Eliminations
Current assets:
Cash and cash equivalents	0		0	$ 0	$ 0
Accounts receivable	(586)		(182)
Prepaid and other current assets	0		0
Total current assets	(586)		(182)
Properties and equipment, net	0		0
Investment in subsidiaries	(2,136,803)		(2,175,604)
Intangible assets, net	0		0
Goodwill	0		0
Equity method investments	0		0
Other assets	0		0
Assets	(2,137,389)		(2,175,786)
Current liabilities:
Accounts payable	(586)		(182)
Accrued interest	0		0
Deferred revenue	0		0
Accrued property taxes	0		0
Other current liabilities	0		0
Total current liabilities	(586)		(182)
Long-term debt	0		0
Other long-term liabilities	0		0
Deferred revenue	0		0
Class B unit	0		0
Equity - partners	(2,136,803)		(2,175,604)
Equity - noncontrolling interest	0		0
Total liabilities and equity	$ (2,137,389)		$ (2,175,786)

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidating Statement of Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues [Abstract]
Affiliates	$ 94,013	$ 93,152	$ 195,441	$ 182,177
Third parties	24,747	15,991	52,203	32,600
Total revenues	118,760	109,143	247,644	214,777
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)	34,533	34,097	70,735	66,586
Depreciation and amortization	24,608	19,945	49,750	38,722
General and administrative	2,673	2,615	5,795	5,249
Total operating costs and expenses	61,814	56,657	126,280	110,557
Operating Income (Loss)	56,946	52,486	121,364	104,220
Equity in earnings of subsidiaries	0	0	0	0
Equity in earnings of equity method investments	1,734	4,053	3,013	5,893
Interest expense	(17,626)	(13,748)	(35,207)	(27,287)
Interest income	526	103	1,041	205
Loss on early extinguishment of debt	0	0	0	(12,225)
Gain on sale of assets and other	(53)	89	33	162
Nonoperating Income (Expense)	(15,419)	(9,503)	(31,120)	(33,252)
Income before income taxes	41,527	42,983	90,244	70,968
State income tax benefit (expense)	(28)	(127)	(110)	(233)
Net income	41,499	42,856	90,134	70,735
Allocation of net income attributable to noncontrolling interests	(1,356)	(1,521)	(3,823)	(3,837)
Net income attributable to the partners	40,143	41,335	86,311	66,898
Other comprehensive income	0	(91)	0	(28)
Comprehensive income attributable to the partners	40,143	41,244	86,311	66,870
Parent
Revenues [Abstract]
Affiliates	0	0	0	0
Third parties	0	0	0	0
Total revenues	0	0	0	0
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)	0	0	0	0
Depreciation and amortization		0	0	0
General and administrative	761	865	2,041	2,020
Total operating costs and expenses	761	865	2,041	2,020
Operating Income (Loss)	(761)	(865)	(2,041)	(2,020)
Equity in earnings of subsidiaries	58,566	48,375	123,618	93,658
Equity in earnings of equity method investments	0	0	0	0
Interest expense	(17,662)	(6,175)	(35,311)	(12,515)
Interest income	0	0	0	0
Loss on early extinguishment of debt				(12,225)
Gain on sale of assets and other	0	0	45	0
Nonoperating Income (Expense)	40,904	42,200	88,352	68,918
Income before income taxes	40,143	41,335	86,311	66,898
State income tax benefit (expense)	0	0	0	0
Net income	40,143	41,335	86,311	66,898
Allocation of net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to the partners	40,143	41,335	86,311	66,898
Other comprehensive income	0	(91)	0	(28)
Comprehensive income attributable to the partners	40,143	41,244	86,311	66,870
Guarantor Restricted Subsidiaries
Revenues [Abstract]
Affiliates	89,522	88,022	183,813	168,798
Third parties	19,540	10,385	39,518	21,388
Total revenues	109,062	98,407	223,331	190,186
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)	31,494	30,871	64,158	59,963
Depreciation and amortization	20,431	15,791	41,432	30,644
General and administrative	1,912	1,750	3,754	3,229
Total operating costs and expenses	53,837	48,412	109,344	93,836
Operating Income (Loss)	55,225	49,995	113,987	96,350
Equity in earnings of subsidiaries	1,881	2,519	7,093	7,420
Equity in earnings of equity method investments	1,734	4,053	3,013	5,893
Interest expense	36	(7,573)	104	(14,772)
Interest income	526	103	1,041	205
Loss on early extinguishment of debt				0
Gain on sale of assets and other	(79)	87	(51)	159
Nonoperating Income (Expense)	4,098	(811)	11,200	(1,095)
Income before income taxes	59,323	49,184	125,187	95,255
State income tax benefit (expense)	(28)	(127)	(110)	(233)
Net income	59,295	49,057	125,077	95,022
Allocation of net income attributable to noncontrolling interests	(729)	(682)	(1,459)	(1,364)
Net income attributable to the partners	58,566	48,375	123,618	93,658
Other comprehensive income	0	(91)	0	(28)
Comprehensive income attributable to the partners	58,566	48,284	123,618	93,630
Non-Guarantor Non-Restricted Subsidiaries
Revenues [Abstract]
Affiliates	4,491	5,130	11,628	13,379
Third parties	5,207	5,606	12,685	11,212
Total revenues	9,698	10,736	24,313	24,591
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)	3,039	3,226	6,577	6,623
Depreciation and amortization	4,177	4,154	8,318	8,078
General and administrative	0	0	0	0
Total operating costs and expenses	7,216	7,380	14,895	14,701
Operating Income (Loss)	2,482	3,356	9,418	9,890
Equity in earnings of subsidiaries	0	0	0	0
Equity in earnings of equity method investments	0	0	0	0
Interest expense	0	0	0	0
Interest income	0	0	0	0
Loss on early extinguishment of debt				0
Gain on sale of assets and other	26	2	39	3
Nonoperating Income (Expense)	26	2	39	3
Income before income taxes	2,508	3,358	9,457	9,893
State income tax benefit (expense)	0	0	0	0
Net income	2,508	3,358	9,457	9,893
Allocation of net income attributable to noncontrolling interests	(627)	(839)	(2,364)	(2,473)
Net income attributable to the partners	1,881	2,519	7,093	7,420
Other comprehensive income	0	0	0	0
Comprehensive income attributable to the partners	1,881	2,519	7,093	7,420
Eliminations
Revenues [Abstract]
Affiliates	0	0	0	0
Third parties	0	0	0	0
Total revenues	0	0	0	0
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)	0	0	0	0
Depreciation and amortization	0	0	0	0
General and administrative	0	0	0	0
Total operating costs and expenses	0	0	0	0
Operating Income (Loss)	0	0	0	0
Equity in earnings of subsidiaries	(60,447)	(50,894)	(130,711)	(101,078)
Equity in earnings of equity method investments	0	0	0	0
Interest expense	0	0	0	0
Interest income	0	0	0	0
Loss on early extinguishment of debt				0
Gain on sale of assets and other	0	0	0	0
Nonoperating Income (Expense)	(60,447)	(50,894)	(130,711)	(101,078)
Income before income taxes	(60,447)	(50,894)	(130,711)	(101,078)
State income tax benefit (expense)	0	0	0	0
Net income	(60,447)	(50,894)	(130,711)	(101,078)
Allocation of net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to the partners	(60,447)	(50,894)	(130,711)	(101,078)
Other comprehensive income	0	91	0	28
Comprehensive income attributable to the partners	$ (60,447)	$ (50,803)	$ (130,711)	$ (101,050)

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 160,963	$ 113,601
Cash flows from investing activities
Additions to properties and equipment	(24,739)	(20,524)
Other Payments to Acquire Businesses	(6,831)	0
Distributions from UNEV in excess of earnings	0
Proceeds from sale of assets	196	635
Proceeds from Noncontrolling Interests		0
Distributions in excess of equity in earnings of equity investments	299	1,654
Net cash used for investing activities	(31,075)	(18,235)
Cash flows from financing activities
Net borrowings (repayments) under credit agreement	(112,000)	290,000
Net intercompany financing activities	0	0
Proceeds from Issuance of common units	114,831	52,634
Redemption of 6.5% Senior Notes	0	(309,750)
Distributions to HEP unitholders	(130,075)	(112,195)
Contributions from general partner	492	995
Distribution to HFC for El Dorado tanks		(103)
Distributions to noncontrolling interests	(3,500)	(3,500)
Units withheld for tax withholding obligations	(58)	(35)
Other	(698)	(730)
Net cash used by financing activities	(131,008)	(82,684)
Increase (decrease) for the period	(1,120)	12,682
Beginning of period	7,776	3,657
End of period	6,656	16,339
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(33,588)	(20,377)
Cash flows from investing activities
Additions to properties and equipment	0	0
Other Payments to Acquire Businesses	0
Distributions from UNEV in excess of earnings	0
Proceeds from sale of assets	0	0
Proceeds from Noncontrolling Interests		0
Distributions in excess of equity in earnings of equity investments	0	0
Net cash used for investing activities	0	0
Cash flows from financing activities
Net borrowings (repayments) under credit agreement	(112,000)	0
Net intercompany financing activities	160,330	389,005
Proceeds from Issuance of common units	114,899	52,383
Redemption of 6.5% Senior Notes		(309,750)
Distributions to HEP unitholders	(130,075)	(112,195)
Contributions from general partner	492	1,072
Distribution to HFC for El Dorado tanks		(103)
Distributions to noncontrolling interests	0	0
Units withheld for tax withholding obligations	(58)	(35)
Other	0	0
Net cash used by financing activities	33,588	20,377
Increase (decrease) for the period	0	0
Beginning of period	2	2
End of period	2	2
Guarantor Restricted Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	182,983	122,025
Cash flows from investing activities
Additions to properties and equipment	(18,829)	(17,670)
Other Payments to Acquire Businesses	(6,831)
Distributions from UNEV in excess of earnings	3,407
Proceeds from sale of assets	196	635
Proceeds from Noncontrolling Interests		3,080
Distributions in excess of equity in earnings of equity investments	299	1,654
Net cash used for investing activities	(21,758)	(12,301)
Cash flows from financing activities
Net borrowings (repayments) under credit agreement	0	290,000
Net intercompany financing activities	(160,330)	(389,005)
Proceeds from Issuance of common units	(68)	251
Redemption of 6.5% Senior Notes		0
Distributions to HEP unitholders	0	0
Contributions from general partner	0	(77)
Distribution to HFC for El Dorado tanks		0
Distributions to noncontrolling interests	0	0
Units withheld for tax withholding obligations	0	0
Other	(698)	(730)
Net cash used by financing activities	(161,096)	(99,561)
Increase (decrease) for the period	129	10,163
Beginning of period	511	301
End of period	640	10,464
Non-Guarantor Non-Restricted Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	18,661	19,373
Cash flows from investing activities
Additions to properties and equipment	(5,910)	(2,854)
Other Payments to Acquire Businesses	0
Distributions from UNEV in excess of earnings	0
Proceeds from sale of assets	0	0
Proceeds from Noncontrolling Interests		0
Distributions in excess of equity in earnings of equity investments	0	0
Net cash used for investing activities	(5,910)	(2,854)
Cash flows from financing activities
Net borrowings (repayments) under credit agreement	0	0
Net intercompany financing activities	0	0
Proceeds from Issuance of common units	0	0
Redemption of 6.5% Senior Notes		0
Distributions to HEP unitholders	0	0
Contributions from general partner	0	0
Distribution to HFC for El Dorado tanks		0
Distributions to noncontrolling interests	(14,000)	(14,000)
Units withheld for tax withholding obligations	0	0
Other	0	0
Net cash used by financing activities	(14,000)	(14,000)
Increase (decrease) for the period	(1,249)	2,519
Beginning of period	7,263	3,354
End of period	6,014	5,873
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(7,093)	(7,420)
Cash flows from investing activities
Additions to properties and equipment	0	0
Other Payments to Acquire Businesses	0
Distributions from UNEV in excess of earnings	(3,407)
Proceeds from sale of assets	0	0
Proceeds from Noncontrolling Interests		(3,080)
Distributions in excess of equity in earnings of equity investments	0	0
Net cash used for investing activities	(3,407)	(3,080)
Cash flows from financing activities
Net borrowings (repayments) under credit agreement	0	0
Net intercompany financing activities	0	0
Proceeds from Issuance of common units	0	0
Redemption of 6.5% Senior Notes		0
Distributions to HEP unitholders	0	0
Contributions from general partner	0	0
Distribution to HFC for El Dorado tanks		0
Distributions to noncontrolling interests	10,500	10,500
Units withheld for tax withholding obligations	0	0
Other	0	0
Net cash used by financing activities	10,500	10,500
Increase (decrease) for the period	0	0
Beginning of period	0	0
End of period	$ 0	$ 0