HOLLY ENERGY PARTNERS LP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - HOLLY ENERGY PARTNERS LP	hepex3226-30x201710q.htm
EX-32.1 - EXHIBIT 32.1 - HOLLY ENERGY PARTNERS LP	hepex3216-30x201710q.htm
EX-31.2 - EXHIBIT 31.2 - HOLLY ENERGY PARTNERS LP	hepex3126-30x201710q.htm
EX-31.1 - EXHIBIT 31.1 - HOLLY ENERGY PARTNERS LP	hepex3116-30x201710q.htm
EX-10.4 - EXHIBIT 10.4 - HOLLY ENERGY PARTNERS LP	hepex104hep-edaamendment.htm
EX-4.1 - EXHIBIT 4.1 - HOLLY ENERGY PARTNERS LP	exhibit41secondsupplementa.htm

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, 2017



¨	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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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 31, 2017, was 64,318,955.

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

		SIGNATURES	48

		Index to Exhibits	49

- 2 -

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, Alon USA, Inc. 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 attacks and the consequences of any such attacks;


•	general economic conditions; 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, 2016, 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.

- 3 -

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, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	16,339		$	3,657
Accounts receivable:
Trade	8,131			7,846
Affiliates	36,607			42,562
	44,738			50,408
Prepaid and other current assets	3,122			2,888
Total current assets	64,199			56,953

Properties and equipment, net	1,311,766			1,328,395
Transportation agreements, net	63,381			66,856
Goodwill	256,498			256,498
Equity method investments	163,360			165,609
Other assets	8,687			9,926
Total assets	$	1,867,891		$	1,884,237

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	8,632		$	10,518
Affiliates	7,296			16,424
	15,928			26,942

Accrued interest	10,550			18,069
Deferred revenue	13,545			11,102
Accrued property taxes	4,396			5,397
Other current liabilities	3,189			3,225
Total current liabilities	47,608			64,735

Long-term debt	1,236,739			1,243,912
Other long-term liabilities	15,717			16,445
Deferred revenue	46,245			47,035

Class B unit	41,682			40,319

Equity:
Partners’ equity:
Common unitholders (64,318,955 and 62,780,503 units issued and outstanding at June 30, 2017 and December 31, 2016, respectively)	518,178			510,975
General partner interest (2% interest)	(130,871		)	(132,832		)
Accumulated other comprehensive income	63			91
Total partners’ equity	387,370			378,234
Noncontrolling interest	92,530			93,557
Total equity	479,900			471,791
Total liabilities and equity	$	1,867,891		$	1,884,237

See accompanying notes.

- 4 -

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,
	2017			2016 ⁽¹⁾			2017			2016 ⁽¹⁾
Revenues:
Affiliates	$	93,152		$	79,179		$	182,177		$	162,025
Third parties	15,991			15,718			32,600			34,882
	109,143			94,897			214,777			196,907
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	34,097			29,212			66,586			57,067
Depreciation and amortization	19,945			15,712			38,722			32,263
General and administrative	2,615			2,863			5,249			5,954
	56,657			47,787			110,557			95,284
Operating income	52,486			47,110			104,220			101,623

Other income (expense):
Equity in earnings of equity method investments	4,053			3,623			5,893			6,388
Interest expense	(13,748		)	(11,276		)	(27,287		)	(21,811		)
Interest income	103			112			205			224
Loss on early extinguishment of debt	—			—			(12,225		)	—
Gain (loss) on sale of assets and other	89			—			162			(8		)
	(9,503		)	(7,541		)	(33,252		)	(15,207		)
Income before income taxes	42,983			39,569			70,968			86,416
State income tax expense	(127		)	(54		)	(233		)	(149		)
Net income	42,856			39,515			70,735			86,267
Allocation of net loss attributable to Predecessor	—			1,960			—			3,110
Allocation of net income attributable to noncontrolling interests	(1,521		)	(2,355		)	(3,837		)	(7,282		)
Net income attributable to the partners	41,335			39,120			66,898			82,095
General partner interest in net income attributable to the partners	(18,328		)	(12,677		)	(35,466		)	(24,779		)
Limited partners’ interest in net income	$	23,007		$	26,443		$	31,432		$	57,316
Limited partners’ per unit interest in earnings—basic and diluted	$	0.36		$	0.45		$	0.49		$	0.96
Weighted average limited partners’ units outstanding	64,086			58,865			63,602			58,761

(1) Retrospectively adjusted as described in Note 1.

See accompanying notes.

- 5 -

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016 ⁽¹⁾			2017			2016⁽¹⁾
Net income	$	42,856		$	39,515		$	70,735		$	86,267

Other comprehensive income:
Change in fair value of cash flow hedging instruments	11			(255		)	87			(938		)
Reclassification adjustment to net income on partial settlement of cash flow hedge	(102		)	113			(115		)	343
Other comprehensive income (loss)	(91		)	(142		)	(28		)	(595		)
Comprehensive income before noncontrolling interest	42,765			39,373			70,707			85,672
Allocation of net loss attributable to Predecessor	—			1,960			—			3,110
Allocation of comprehensive income to noncontrolling interests	(1,521		)	(2,355		)	(3,837		)	(7,282		)
Comprehensive income attributable to Holly Energy Partners	$	41,244		$	38,978		$	66,870		$	81,500

(1) Retrospectively adjusted as described in Note 1.

See accompanying notes.

- 6 -

Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Six Months Ended June 30,
	2017			2016 ⁽¹⁾
Cash flows from operating activities
Net income	$	70,735		$	86,267
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	38,722			32,263
(Gain) loss on sale of assets	(133		)	5
Amortization of deferred charges	1,504			1,376
Amortization of restricted and performance units	1,109			1,193
Earnings distributions greater (less) than income from equity investments	594			(414		)
Loss on early extinguishment of debt	12,225			—
(Increase) decrease in operating assets:
Accounts receivable—trade	(285		)	2,564
Accounts receivable—affiliates	6,033			(10,183		)
Prepaid and other current assets	(234		)	416
Increase (decrease) in operating liabilities:
Accounts payable—trade	104			(637		)
Accounts payable—affiliates	(9,128		)	(2,454		)
Accrued interest	(7,519		)	(91		)
Deferred revenue	1,653			948
Accrued property taxes	(1,001		)	1,409
Other current liabilities	(442		)	(979		)
Other, net	(336		)	(381		)
Net cash provided by operating activities	113,601			111,302

Cash flows from investing activities
Additions to properties and equipment	(20,524		)	(32,667		)
Purchase of Woods Cross refinery processing units	—			(42,718		)
Purchase of interest in Cheyenne Pipeline	—			(42,500		)
Proceeds from sale of assets	635			18
Distributions in excess of equity in earnings of equity investments	1,654			1,496
Net cash used for investing activities	(18,235		)	(116,371		)

Cash flows from financing activities
Borrowings under credit agreement	479,000			239,000
Repayments of credit agreement borrowings	(189,000		)	(165,000		)
Redemption of 6.5% Senior Notes	(309,750		)	—
Proceeds from issuance of common units	52,634			13,690
Distributions to HEP unitholders	(112,195		)	(91,109		)
Distributions to noncontrolling interest	(3,500		)	(2,500		)
Distribution to HFC for Tulsa tank acquisition	—			(39,500		)
Distribution to HFC for Osage acquisition	—			(1,245		)
Distribution to HFC for El Dorado tanks	(103		)	—
Contributions from HFC for acquisitions	—			45,707
Contributions from general partner	995			120
Purchase of units for incentive grants	—			(784		)
Deferred financing costs	—			(3,084		)
Other	(765		)	(357		)
Net cash used by financing activities	(82,684		)	(5,062		)

Cash and cash equivalents
Increase (decrease) for the period	12,682			(10,131		)
Beginning of period	3,657			15,013
End of period	$	16,339		$	4,882

(1) Retrospectively adjusted as described in Note 1.

See accompanying notes.

- 7 -

Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

(In thousands)



	Common Units			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity

Balance December 31, 2016	$	510,975		$	(132,832	)	$	91		$	93,557		$	471,791
Issuance of common units	52,383			—			—			—			52,383
Contribution from HFC	—			1,072			—			—			1,072
Distribution to HFC for acquisition	—			(103		)	—			—			(103		)
Distributions to HEP unitholders	(77,748		)	(34,447		)	—			—			(112,195		)
Distributions to noncontrolling interest	—			—			—			(3,500		)	(3,500		)
Amortization of restricted and performance units	1,109			—			—			—			1,109
Class B unit accretion	(1,337		)	(27		)	—			—			(1,364		)
Net income	32,796			35,466			—			2,473			70,735
Other comprehensive income	—			—			(28		)	—			(28		)
Balance June 30, 2017	$	518,178		$	(130,871	)	$	63		$	92,530		$	479,900

See accompanying notes.

- 8 -

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 which is 36% owned (including the 2% general partner interest) by HollyFrontier Corporation (“HFC”) and its subsidiaries as of June 30, 2017. 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.

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 Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 75% interest in UNEV Pipeline, LLC (“UNEV”), a 50% interest in Frontier Aspen LLC, a 50% interest in Osage Pipe Line Company, LLC (“Osage”), a 50% interest in Cheyenne Pipeline LLC and a 25% interest in SLC 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 13.

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, 2016. 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, 2017.

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts, our Predecessor's (defined below) 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. GAAP requires transfers of a business between entities under common control to be accounted for as though the transfer occurred as of the beginning of the period of transfer, and prior period financial statements and financial information are retrospectively adjusted to include the historical results and assets of the acquisitions from HFC for all periods presented prior to the effective dates of each acquisition. We refer to the historical results of the acquisitions prior to their respective acquisition dates as those of our "Predecessor." Many of these transactions are cash purchases and do not involve the issuance of equity; however, GAAP requires the retrospective adjustment of financial statements. Therefore, in such transactions, the prior year balance sheet includes as equity the amount of cost incurred by HFC to that date. See “Acquisitions” below for further discussion as well as effects of the retrospective adjustments.

Acquisitions

Osage

On February 22, 2016, HFC obtained a 50% membership interest in Osage in a non-monetary exchange for a 20-year terminalling services agreement, whereby a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico requiring terminalling in or through El Paso, Texas. Osage is the owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also connects to the Jayhawk pipeline serving the CHS Inc. refinery in McPherson, Kansas. The Osage Pipeline is the primary pipeline supplying HFC’s El Dorado refinery with crude oil.

- 9 -

Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we agreed to build two connections on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange, we became the named operator of the Osage Pipeline and transitioned into that role on September 1, 2016. Since we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis of its 50% membership interest in Osage of $44.5 million offset by our net carrying basis in the El Paso terminal of $12.1 million with the difference recorded as a contribution from HFC. However, since these transactions were concurrent, there was no impact on periods prior to February 22, 2016.

Tulsa Tanks

On March 31, 2016, we acquired crude oil tanks (the “Tulsa Tanks”) located at HFC’s Tulsa refinery from an affiliate of Plains All American Pipeline, L.P. (“Plains”) for cash consideration of $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accounted for the transaction as a financing arrangement. Accordingly, the tanks had remained on HFC’s balance sheet and were being depreciated for accounting purposes.

As we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis in the net assets acquired. We have retrospectively adjusted our financial position and operating results as if these units were owned for all periods while we were under common control of HFC.

Cheyenne Pipeline

On June 3, 2016, we acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne Pipeline, in exchange for a contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline LLC will continue to be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.

Woods Cross Operating

Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross Refinery, for cash consideration of $278 million. The consideration was funded with $103 million in proceeds from the private placement of 3,420,000 common units with the balance funded with borrowings under our credit facility. In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC. As of June 30, 2017, these commitments provide minimum annualized revenues of $57 million.

The Utah Division of Air Quality issued an air quality permit to HollyFrontier Woods Cross Refining LLC (“HFC Woods Cross Refining”) authorizing the expansion units at the Woods Cross Refinery. The appeal proceeding challenging the Utah Department of Environmental Quality’s decision to uphold the air quality permit was taken under advisement by the Utah Supreme Court in June 2017, and the court issued a decision in favor of the state of Utah and HFC. As a result, the purchase agreement remedies we had against HFC in the event of an unfavorable ruling in the appeal proceeding are no longer applicable.

The following tables present lines in our previously reported income statement for the three and six months ended June 30, 2016, that were impacted by Predecessor transactions, and retrospectively adjusts only the acquisition of Woods Cross Operating as the Tulsa Tanks acquisition included Predecessor transactions in the previously reported income statement for the three and six months ended June 30, 2016. However, the presentation of the Tulsa Tanks’ Predecessor transactions have been modified as shown in the table below.

- 10 -



	Three Months Ended June 30, 2016
	Holly Energy Partners, L.P.(Previously reported)		Tulsa Tanks		Woods Cross Operating		Holly Energy Partners, L.P. (Currently reported)
	(In Thousands)
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	$	27,255	$	—	$	1,957	$	29,212
Depreciation and amortization	15,709		—		3		15,712
Allocation of net loss attributable to predecessor	—		—		1,960		1,960



	Six Months Ended June 30, 2016
	Holly Energy Partners, L.P.(Previously reported)		Tulsa Tanks		Woods Cross Operating		Holly Energy Partners, L.P. (Currently reported)
	(In Thousands)
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	$	54,177	$	—	$	2,890	$	57,067
Depreciation and amortization	32,260		—		3		32,263
Allocation of net loss attributable to predecessor	—		217		2,893		3,110

The following tables present lines in our previously reported cash flows for the six months ended June 30, 2016, that were impacted by Predecessor transactions, and retrospectively adjusts only the acquisition of Woods Cross Operating as the Tulsa Tanks acquisition included Predecessor transactions in the previously reported cash flows for the six months ended June 30, 2016.



	Six Months Ended June 30, 2016
	Holly Energy Partners, L.P.(Previously reported)			Woods Cross Operating			Holly Energy Partners, L.P. (Currently reported)
Cash flows from operating activities	(In Thousands)
Net income	$	89,160		$	(2,893	)	$	86,267
Depreciation and amortization	32,260			$	3		32,263
Net cash provided by operating activities	$	114,192		$	(2,890	)	$	111,302

Cash flows from investing activities
Acquisition of refinery processing units	—			(42,718		)	(42,718		)
Net cash used for investing activities	$	(73,653	)	$	(42,718	)	$	(116,371	)

Cash flows from financing activities
Contributions from HFC for acquisitions	$	99		$	45,608		$	45,707
Net cash provided (used) by financing activities	$	(50,670	)	$	45,608		$	(5,062	)

Accounting Pronouncements Adopted During the Periods Presented

Earnings Per Unit

In April 2015, an accounting standard update was issued requiring changes to the allocation of the earnings or losses of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating historical earnings per unit. We adopted this standard as of January 1, 2016. In connection with the dropdown of assets from HFC’s Tulsa refinery on March 31, 2016, we reduced net income by $0.2 million for the three and six months ended June 30, 2016, and in connection with the purchase of HFC’s Woods Cross refinery units on

- 11 -

October 1, 2016, we reduced net income by $2.0 million and $2.9 million, respectively, for the three and six months ended June 30, 2016. This reduction had no impact on the historical earnings per limited partner unit.

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, results of operations and cash flows. As permitted by the standard, we continue to account for forfeitures on an estimated basis.

Accounting Pronouncements Not Yet Adopted

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 has an effective date of January 1, 2018, and we intend to account 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. Our preparation for adoption of this standard is in progress, and we are currently evaluating terms, conditions and our performance obligations of our existing contracts with customers. We are evaluating the effect of this standard on our revenue recognition policies and whether it will have a material impact on our financial condition or results of operations.

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 has an effective date of January 1, 2018, and we are evaluating its impact.

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 will become effective beginning with our 2018 reporting year. We are evaluating the impact of this standard.

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.


Note 2:	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.

- 12 -

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



		June 30, 2017				December 31, 2016
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	63	$	63	$	91	$	91

Liabilities:
6.5% Senior notes	Level 2	$	—	$	—	$	297,519	$	308,250
6% Senior notes	Level 2	393,739		418,000		393,393		415,500
		$	393,739	$	418,000	$	690,912	$	723,750

Level 2 Financial Instruments

Our senior notes and interest rate swaps 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. The fair value of our interest rate swaps is based on the net present value of expected future cash flows related to both variable and fixed-rate legs of the swap agreement. This measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input.

See Note 6 for additional information on these instruments.


Note 3:	Properties and Equipment

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



	June 30, 2017		December 31, 2016
	(In thousands)
Pipelines, terminals and tankage	$	1,249,383	$	1,246,746
Refinery assets	347,285		346,058
Land and right of way	65,337		65,331
Construction in progress	40,914		28,753
Other	27,542		27,133
	1,730,461		1,714,021
Less accumulated depreciation	418,695		385,626
	$	1,311,766	$	1,328,395

We capitalized $0.4 million and $0.3 million in interest attributable to construction projects during the six months ended June 30, 2017 and 2016, respectively.

Depreciation expense was $34.9 million and $28.5 million for the six months ended June 30, 2017 and 2016, respectively, and includes depreciation of assets acquired under capital leases.


Note 4:	Transportation Agreements

Our transportation agreements are intangible assets that represent a portion of the total purchase price of certain assets acquired from Alon in 2005 and from HFC in 2008 prior to HEP becoming a consolidated VIE of HFC. The Alon agreement is being amortized over 30 years ending 2035 (the initial 15-year term of the agreement plus an expected 15-year extension period), and the HFC agreement is being amortized over 15 years ending 2023 (the term of the HFC agreement).

- 13 -

The carrying amounts of our transportation agreements are as follows:



	June 30, 2017		December 31, 2016
	(In thousands)
Alon transportation agreement	$	59,933	$	59,933
HFC transportation agreement	74,231		74,231
Other	50		50
	134,214		134,214
Less accumulated amortization	70,833		67,358
	$	63,381	$	66,856

Amortization expense was $3.5 million for each of the six months ended June 30, 2017 and 2016.

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 5:	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 $1.3 million and $1.3 million for the three months ended June 30, 2017 and 2016, respectively, and $3.0 million and $2.9 million for the six months ended June 30, 2017 and 2016.

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, 2017, we had two types of incentive-based awards outstanding, which are described below. The compensation cost charged against income was $0.6 million and $0.5 million for the three months ended June 30, 2017 and 2016, respectively, and $0.9 million and $1.2 million for the six months ended June 30, 2017 and 2016. 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, 2017, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,409,261 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.

Restricted Units

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

The fair value of each restricted 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.

- 14 -

A summary of restricted unit activity and changes during the six months ended June 30, 2017, is presented below:



Restricted Units	Units		Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2017 (nonvested)	123,988		$	32.96
Granted	20,348		36.01
Forfeited	(17,653	)	29.75
Outstanding at June 30, 2017 (nonvested)	126,683		$	33.90

As of June 30, 2017, there was $1.6 million of total unrecognized compensation expense related to nonvested restricted unit grants, which is expected to be recognized over a weighted-average period of 1.0 year.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives 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, 2017, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target number of performance units granted.

We did not grant any performance units during the six months ended June 30, 2017. Performance units granted in 2016 vest over a three-year performance period ending December 31, 2019, 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 during the six months ended June 30, 2017, is presented below:



Performance Units	Units
Outstanding at January 1, 2017 (nonvested)	49,520
Vesting and transfer of common units to recipients	(2,262	)
Forfeited	(21,228	)
Outstanding at June 30, 2017 (nonvested)	26,030

The grant-date fair value of performance units vested and transferred to recipients during the six months ended June 30, 2017, was $0.1 million. Based on the weighted average fair value of performance units outstanding at June 30, 2017, of $0.9 million, there was $0.5 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.8 years.


Note 6:	Debt

Credit Agreement

At June 30, 2017, we had a $1.2 billion senior secured revolving credit facility (the “Credit Agreement”) expiring in November 2018. On July 27, 2017, the Credit Agreement was amended, increasing the size of the facility from $1.2 billion to $1.4 billion and extending the expiration to 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.

- 15 -

We may prepay all loans outstanding 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, 2017.

Senior Notes

On January 4, 2017, we redeemed the $300 million aggregate principal amount of 6.5% senior notes (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.

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”). We used the net proceeds 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, 2017. 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.

Long-term Debt

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



	June 30, 2017			December 31, 2016
	(In thousands)
Credit Agreement
Amount outstanding	$	843,000		$	553,000

6% Senior Notes
Principal	400,000			400,000
Unamortized debt issuance costs	(6,261		)	(6,607		)
	393,739			393,393
6.5% Senior Notes
Principal	—			300,000
Unamortized discount and debt issuance costs	—			(2,481		)
	—			297,519

Total long-term debt	$	1,236,739		$	1,243,912

Interest Rate Risk Management

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of June 30, 2017, we had two interest rate swaps with identical terms that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement advances. The swaps effectively converted $150 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.25% as of June 30, 2017, which equaled an effective interest rate of 2.99%. Both of these swap contracts matured on July 31, 2017.

We have designated these interest rate swaps as cash flow hedges. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined these interest rate swaps are effective in offsetting the variability in interest payments on $150 million of our variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedges on a quarterly basis to their fair values with the offsetting fair value adjustments to accumulated other comprehensive income (loss). Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swaps against the expected

- 16 -

future interest payments on $150 million of our variable rate debt. Any ineffectiveness is recorded directly to interest expense. As of June 30, 2017, we had no ineffectiveness on our cash flow hedges.

At June 30, 2017, we had accumulated other comprehensive income of $0.1 million that related to our current cash flow hedging instruments. Approximately $0.1 million will be transferred from accumulated other comprehensive income into interest expense as interest is paid on the underlying swap agreements during the third quarter of 2017.

Additional information on our interest rate swaps is as follows:



Derivative Instrument	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(In thousands)
June 30, 2017
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contracts ($150 million of LIBOR-based debt interest)	Other current assets	$	63	Accumulated other comprehensive income	$	63
		$	63		$	63

December 31, 2016
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contracts ($150 million of LIBOR-based debt interest)	Other current assets	$	91	Accumulated other comprehensive income	$	91
		$	91		$	91

Interest Expense and Other Debt Information

Interest expense consists of the following components:



	Six Months Ended June 30,
	2017		2016
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	13,299	$	10,284
6.5% Senior Notes	162		9,757
6% Senior Notes	12,000		—
Amortization of discount and deferred debt issuance costs	1,536		1,376
Commitment fees and other	720		679
Total interest incurred	27,717		22,096
Less capitalized interest	430		285
Net interest expense	$	27,287	$	21,811
Cash paid for interest	$	33,700	$	20,736

Capital Lease Obligations

Our capital lease obligations relate to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under capital leases was $5.0 million and $4.9 million as of June 30, 2017 and December 31, 2016, respectively, with accumulated depreciation of $2.9 million and $2.4 million as of June 30, 2017 and December 31, 2016, respectively. We include depreciation of capital leases in depreciation and amortization in our consolidated statements of income.


Note 7:	Significant Customers

All revenues are domestic revenues, of which 91% are currently generated from our two largest customers: HFC and Alon.

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

- 17 -



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
HFC	85	%	83	%	85	%	82	%
Alon	6	%	9	%	7	%	8	%


Note 8:	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 based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of June 30, 2017, these agreements with HFC require minimum annualized payments to us of $322 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 $93.2 million and $79.2 million for the three months ended June 30, 2017 and 2016, respectively, and $182.2 million and $162.0 million for the six months ended June 30, 2017 and 2016, 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, 2017 and 2016, and $1.2 million for each of the six months ended June 30, 2017 and 2016.


•	We reimbursed HFC for costs of employees supporting our operations of $11.4 million and $9.5 million for the three months ended June 30, 2017 and 2016, respectively, and $22.9 million and $19.4 million for the six months ended June 30, 2017 and 2016, respectively.


•	HFC reimbursed us $1.5 million and $5.0 million for the three months ended June 30, 2017 and 2016, respectively, and $2.8 million and $6.7 million for the six months ended June 30, 2017 and 2016, respectively, for expense and capital projects.


•	We distributed $31.7 million and $25.3 million for the three months ended June 30, 2017 and 2016, respectively, and $61.9 million and $49.8 million for the six months ended June 30, 2017 and 2016, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.


•	Accounts receivable from HFC were $36.6 million and $42.6 million at June 30, 2017, and December 31, 2016, respectively.


•	Accounts payable to HFC were $7.3 million and $16.4 million at June 30, 2017, and December 31, 2016, respectively.

•

Revenues for the six months ended June 30, 2017 and 2016, include $2.7 million and $5.5 million, respectively, of shortfall payments billed to HFC in 2016 and 2015, respectively. Deferred revenue in the consolidated balance sheets at June 30, 2017 and December 31, 2016, includes $5.9 million and $5.6 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 $5.9 million deferred at June 30, 2017.

- 18 -


Note 9:	Partners’ Equity

As of June 30, 2017, HFC held 22,380,030 of our common units and the 2% general partner interest, which together constituted a 36% ownership interest in us. Additionally, HFC owned all incentive distribution rights.

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, 2017, HEP issued 1,538,452 units under this program, providing $52.4 million in net proceeds. In connection with this program and to maintain the 2% general partner interest, HFC made capital contributions totaling $1.1 million. As of June 30, 2017, HEP has issued 2,241,907 units under this program, providing $77.1 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 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 includes incentive distributions that are declared subsequent to quarter end. After incentive distributions and other priority allocations are allocated to the general partner, the remaining net income attributable to HEP is 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,
	2017		2016			2017		2016
	(In thousands)
General partner interest in net income	$	827	$	540		$	1,338	$	1,170
General partner incentive distribution	17,501		12,137			34,128		23,609
Net loss attributable to Predecessor	—		(1,960		)	—		(3,110		)
Total general partner interest in net income	$	18,328	$	10,717		$	35,466	$	21,669

Cash Distributions

Our general partner, HEP Logistics, is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels.

On July 27, 2017, we announced our cash distribution for the second quarter of 2017 of $0.6325 per unit. The distribution is payable on all common and general partner units and will be paid August 14, 2017, to all unitholders of record on August 7, 2017.

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,
	2017		2016		2017		2016
	(In thousands, except per unit data)
General partner interest in distribution	$	1,188	$	978	$	2,336	$	1,927
General partner incentive distribution	17,501		12,137		34,128		23,609
Total general partner distribution	18,689		13,115		36,464		25,536
Limited partner distribution	40,682		34,575		80,314		68,302
Total regular quarterly cash distribution	$	59,371	$	47,690	$	116,778	$	93,838
Cash distribution per unit applicable to limited partners	$	0.6325	$	0.5850	$	1.2525	$	1.1600

- 19 -

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 10:	Net Income Per Limited Partner Unit

Net income per unit applicable to the limited partners is computed using the two-class method, because we have more than one class of participating securities. The classes of participating securities as of June 30, 2017, included common units, general partner units and incentive distribution rights (IDRs). 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. The dilutive securities are immaterial for all periods presented.

When our financial statements are retrospectively adjusted after a dropdown transaction, the earnings of the acquired business, prior to the closing of the transaction, are allocated entirely to our general partner and presented as net income (loss) attributable to Predecessors. The earnings per unit of our limited partners prior to the close of the transaction do not change as a result of the dropdown. After the closing of a dropdown transaction, the earnings of the acquired business are allocated in accordance with our partnership agreement as previously described.

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,
	2017			2016			2017			2016
	(In thousands)
Net income attributable to the partners	$	41,335		$	39,120		$	66,898		$	82,095
Less: General partner’s distribution declared (including IDRs)	(18,689		)	(13,115		)	(36,464		)	(25,536		)
Limited partner’s distribution declared on common units	(40,682		)	(34,575		)	(80,314		)	(68,302		)
Distributions in excess of net income attributable to the partners	$	(18,036	)	$	(8,570	)	$	(49,880	)	$	(11,743	)

- 20 -



	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
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

Three Months Ended June 30, 2016
Net income attributable to the partners:
Distributions declared	$	13,115		$	34,575		$	47,690
Distributions in excess of net income attributable to the partners	(171		)	(8,399		)	(8,570		)
Net income attributable to the partners	$	12,944		$	26,176		$	39,120
Weighted average limited partners' units outstanding				58,865
Limited partners' per unit interest in earnings - basic and diluted				$	0.45



	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
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

Six Months Ended June 30, 2016
Net income attributable to partnership:
Distributions declared	$	25,536		$	68,302		$	93,838
Distributions in excess of net income attributable to partnership	(234		)	(11,509		)	(11,743		)
Net income attributable to partnership	$	25,302		$	56,793		$	82,095
Weighted average limited partners' units outstanding				58,761
Limited partners' per unit interest in earnings - basic and diluted				$	0.96

- 21 -


Note 11:	Environmental

We incurred no expenses for environmental remediation obligations for the three and six months ended June 30, 2017, and $0.2 million of expenses for the three and six months ended June 30, 2016. The accrued environmental liability, net of expected recoveries from indemnifying parties, reflected in our consolidated balance sheets was $6.5 million and $7.1 million at June 30, 2017, and December 31, 2016, respectively, of which $4.9 million and $5.4 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, 2017, and December 31, 2016, our consolidated balance sheets included additional accrued environmental liabilities of $0.8 million and $0.9 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 12:	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 13:	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,
	2017			2016			2017			2016

Revenues:
Pipelines and terminals - affiliate	$	75,613		$	75,004		$	145,258		$	153,343
Pipelines and terminals - third-party	15,991			15,718			32,600			34,882
Refinery processing units - affiliate	17,539			4,175			36,919			8,682
Total segment revenues	$	109,143		$	94,897		$	214,777		$	196,907

Segment operating income:
Pipelines and terminals	$	49,164		$	49,481		$	95,649		$	106,729
Refinery processing units	5,937			492			13,820			848
Total segment operating income	55,101			49,973			109,469			107,577
Unallocated general and administrative expenses	(2,615		)	(2,863		)	(5,249		)	(5,954		)
Interest and financing costs, net	(13,645		)	(11,164		)	(39,307		)	(21,587		)
Equity in earnings of unconsolidated affiliates	4,053			3,623			5,893			6,388
Gain (loss) on sale of assets and other	89			—			162			(8		)
Income before income taxes	$	42,983		$	39,569		$	70,968		$	86,416

Capital Expenditures:
Pipelines and terminals	$	12,157		$	13,770		$	20,286		$	31,644
Refinery processing units	102			19,431			238			43,742
Total capital expenditures	$	12,259		$	33,201		$	20,524		$	75,386

- 22 -



	June 30, 2017		December 31, 2016
	(in thousands)
Identifiable assets:
Pipelines and terminals	$	1,354,198	$	1,369,756
Refinery processing units	334,796		342,506
Other	178,897		171,975
Total identifiable assets	$	1,867,891	$	1,884,237


Note 14:	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.

In conjunction with the preparation of our Condensed Consolidating Balance Sheet and Statements of Comprehensive Income included below, we identified and corrected the presentation of noncontrolling interests presented in the eliminations column in prior periods to reflect such balances and activity within the respective guarantor and non-guarantor subsidiaries columns.

- 23 -

Condensed Consolidating Balance Sheet



June 30, 2017	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	10,464	$	5,873	$	—		$	16,339
Accounts receivable	—		40,497		4,483		(242		)	44,738
Prepaid and other current assets	92		2,718		312		—			3,122
Total current assets	94		53,679		10,668		(242		)	64,199

Properties and equipment, net	—		947,611		364,155		—			1,311,766
Investment in subsidiaries	790,632		277,591		—		(1,068,223		)	—
Transportation agreements, net	—		63,381		—		—			63,381
Goodwill	—		256,498		—		—			256,498
Equity method investments	—		163,360		—		—			163,360
Other assets	725		7,962		—		—			8,687
Total assets	$	791,451	$	1,770,082	$	374,823	$	(1,068,465	)	$	1,867,891

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	30	$	15,236	$	904	$	(242	)	$	15,928
Accrued interest	10,000		550		—		—			10,550
Deferred revenue	—		12,641		904		—			13,545
Accrued property taxes	—		1,696		2,700		—			4,396
Other current liabilities	26		3,160		3		—			3,189
Total current liabilities	10,056		33,283		4,511		(242		)	47,608

Long-term debt	393,739		843,000		—		—			1,236,739
Other long-term liabilities	286		15,240		191		—			15,717
Deferred revenue	—		46,245		—		—			46,245
Class B unit	—		41,682		—		—			41,682
Equity - partners	387,370		790,632		277,591		(1,068,223		)	387,370
Equity - noncontrolling interest	—		—		92,530		—			92,530
Total liabilities and equity	$	791,451	$	1,770,082	$	374,823	$	(1,068,465	)	$	1,867,891

- 24 -

Condensed Consolidating Balance Sheet



December 31, 2016	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	301	$	3,354	$	—		$	3,657
Accounts receivable	—		45,056		5,554		(202		)	50,408
Prepaid and other current assets	11		2,633		244		—			2,888
Total current assets	13		47,990		9,152		(202		)	56,953

Properties and equipment, net	—		957,045		371,350		—			1,328,395
Investment in subsidiaries	1,086,008		280,671		—		(1,366,679		)	—
Transportation agreements, net	—		66,856		—		—			66,856
Goodwill	—		256,498		—		—			256,498
Equity method investments	—		165,609		—		—			165,609
Other assets	725		9,201		—		—			9,926
Total assets	$	1,086,746	$	1,783,870	$	380,502	$	(1,366,881	)	$	1,884,237

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—	$	24,245	$	2,899	$	(202	)	$	26,942
Accrued interest	17,300		769		—		—			18,069
Deferred revenue	—		8,797		2,305		—			11,102
Accrued property taxes	—		4,514		883		—			5,397
Other current liabilities	14		3,208		3		—			3,225
Total current liabilities	17,314		41,533		6,090		(202		)	64,735

Long-term debt	690,912		553,000		—		—			1,243,912
Other long-term liabilities	286		15,975		184		—			16,445
Deferred revenue	—		47,035		—		—			47,035
Class B unit	—		40,319		—		—			40,319
Equity - partners	378,234		1,086,008		280,671		(1,366,679		)	378,234
Equity - noncontrolling interest	—		—		93,557		—			93,557
Total liabilities and equity	$	1,086,746	$	1,783,870	$	380,502	$	(1,366,881	)	$	1,884,237

- 25 -

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 (loss) 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 Holly Energy Partners	41,335			48,375			2,519			(50,894		)	41,335
Other comprehensive income	(91		)	(91		)	—			91			(91		)
Comprehensive income attributable to Holly Energy Partners	$	41,244		$	48,284		$	2,519		$	(50,803	)	$	41,244

- 26 -

Condensed Consolidating Statement of Comprehensive Income



Three Months Ended June 30, 2016 ⁽¹⁾	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	74,787		$	4,392		$	—		$	79,179
Third parties	—			11,691			4,027			—			15,718
	—			86,478			8,419			—			94,897
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			26,401			2,811			—			29,212
Depreciation and amortization	—			11,925			3,787			—			15,712
General and administrative	971			1,892			—			—			2,863
	971			40,218			6,598			—			47,787
Operating income (loss)	(971		)	46,260			1,821			—			47,110

Other income (expense):
Equity in earnings of subsidiaries	45,164			1,370			—			(46,534		)	—
Equity in earnings of equity method investments	—			3,623			—			—			3,623
Interest expense	(5,073		)	(6,203		)	—			—			(11,276		)
Interest income	—			107			5			—			112
	40,091			(1,103		)	5			(46,534		)	(7,541		)
Income before income taxes	39,120			45,157			1,826			(46,534		)	39,569
State income tax expense	—			(54		)	—			—			(54		)
Net income	39,120			45,103			1,826			(46,534		)	39,515
Allocation of net loss to Predecessor	—			1,960			—			—			1,960
Allocation of net income attributable to noncontrolling interests	—			(1,898		)	(457		)	—			(2,355		)
Net income attributable to Holly Energy Partners	39,120			45,165			1,369			(46,534		)	39,120
Other comprehensive (loss)	(142		)	(142		)	—			142			(142		)
Comprehensive income attributable to Holly Energy Partners	$	38,978		$	45,023		$	1,369		$	(46,392	)	$	38,978

(1) Retrospectively adjusted as described in Note 1.

- 27 -

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

- 28 -

Condensed Consolidating Statement of Comprehensive Income



Six Months Ended June 30, 2016 ⁽¹⁾	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	147,039		$	14,986		$	—		$	162,025
Third parties	—			22,423			12,459			—			34,882
	—			169,462			27,445			—			196,907
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			51,225			5,842			—			57,067
Depreciation and amortization	—			24,718			7,545			—			32,263
General and administrative	2,136			3,818			—			—			5,954
	2,136			79,761			13,387			—			95,284
Operating income (loss)	(2,136		)	89,701			14,058			—			101,623

Other income (expense):
Equity in earnings (loss) of subsidiaries	94,154			10,553			—			(104,707		)	—
Equity in earnings of equity method investments	—			6,388			—			—			6,388
Interest expense	(10,140		)	(11,671		)	—			—			(21,811		)
Interest income	—			212			12			—			224
Gain (loss) on sale of assets and other	—			(9		)	1			—			(8		)
	84,014			5,473			13			(104,707		)	(15,207		)
Income (loss) before income taxes	81,878			95,174			14,071			(104,707		)	86,416
State income tax expense	—			(149		)	—			—			(149		)
Net income (loss)	81,878			95,025			14,071			(104,707		)	86,267
Allocation of net loss to Predecessor				3,110			—			—			3,110
Allocation of net income attributable to noncontrolling interests	—			(3,764		)	(3,518		)	—			(7,282		)
Net income (loss) attributable to Holly Energy Partners	81,878			94,371			10,553			(104,707		)	82,095
Other comprehensive income (loss)	(595		)	(595		)	—			595			(595		)
Comprehensive income (loss)	$	81,283		$	93,776		$	10,553		$	(104,112	)	$	81,500

(1) Retrospectively adjusted as described in Note 1.

- 29 -

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	$	(20,412	)	$	122,060		$	19,373		$	(7,420	)	$	113,601

Cash flows from investing activities
Additions to properties and equipment	—			(17,670		)	(2,854		)	—			(20,524		)
Distributions from UNEV in excess of earnings	—			3,080			—			(3,080		)	—
Proceeds from sale of assets	—			635			—			—			635
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		)	—			—			—
Proceeds from issuance of common units	52,383			251			—			—			52,634
Contribution from general partner	1,072			(77		)	—			—			995
Redemption of senior notes	(309,750		)	—			—			—			(309,750		)
Distributions to HEP unitholders	(112,195		)	—			—			—			(112,195		)
Distribution to HFC for El Dorado tanks	(103		)	—			—			—			(103		)
Distributions to noncontrolling interests	—			—			(14,000		)	10,500			(3,500		)
Other	—			(765		)	—			—			(765		)
	20,412			(99,596		)	(14,000		)	10,500			(82,684		)

Cash and cash equivalents
Increase 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

- 30 -

Condensed Consolidating Statement of Cash Flows



Six Months Ended June 30, 2016 ⁽¹⁾	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(10,608	)	$	110,255		$	19,155		$	(7,500	)	$	111,302

Cash flows from investing activities
Additions to properties and equipment	—			(18,440		)	(14,227		)	—			(32,667		)
Purchase of Woods Cross refinery processing units	—			(42,718		)	—			—			(42,718		)
Purchase of Cheyenne Pipeline	—			(42,500		)	—			—			(42,500		)
Proceeds from sale of assets	—			18			—			—			18
Distributions in excess of equity in earnings of equity investments	—			1,496			—			—			1,496
	—			(102,144		)	(14,227		)	—			(116,371		)

Cash flows from financing activities
Net repayments under credit agreement	—			74,000			—			—			74,000
Net intercompany financing activities	86,789			(86,789		)	—			—			—
Proceeds from issuance of common units	14,586			(896		)	—			—			13,690
Distributions to HEP unitholders	(91,109		)	—			—			—			(91,109		)
Distributions to noncontrolling interests	—			—			(10,000		)	7,500			(2,500		)
Contributions from general partner for Osage	31,285			(31,285		)	—			—			—
Distributions to HFC for Tulsa Tank acquisition	(30,378		)	(9,122		)	—			—			(39,500		)
Distribution to HFC for Osage	—			(1,245		)	—			—			(1,245		)
Contribution from HFC for acquisitions	99			45,608			—			—			45,707
Contributions from general partner	120			—			—			—			120
Purchase of units for incentive grants	(784		)	—			—			—			(784		)
Deferred financing costs	—			(3,084		)	—			—			(3,084		)
Other	—			(357		)	—			—			(357		)
	10,608			(13,170		)	(10,000		)	7,500			(5,062		)

Cash and cash equivalents
Decrease for the period	—			(5,059		)	(5,072		)	—			(10,131		)
Beginning of period	2			5,452			9,559			—			15,013
End of period	$	2		$	393		$	4,487		$	—		$	4,882

(1) Retrospectively adjusted as described in Note 1.

- 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, 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 Alon USA, Inc’s (“Alon”) refinery in Big Spring, Texas. HEP, through its subsidiaries and joint ventures, owns and/or operates petroleum product and crude gathering 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 a 36% interest in us, including the 2% general partnership interest, as of June 30, 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 or store, and therefore, we are not directly exposed to changes in commodity prices.

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

Acquisitions

On February 22, 2016, HFC obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in a non-monetary exchange for a 20-year terminalling services agreement, whereby a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Osage is the owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also has a connection to the Jayhawk pipeline that services the CHS Inc. refinery in McPherson, Kansas. The Osage Pipeline is the primary pipeline that supplies HFC’s El Dorado Refinery with crude oil.

On March 31, 2016, we acquired crude oil tanks located at HFC’s Tulsa refinery from an affiliate of Plains All American Pipeline, L.P. (“Plains”) for $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accounted for the transaction as a financing arrangement. Accordingly, the tanks remained on HFC’s balance sheet and were depreciated for accounting purposes. In connection with this transaction, we entered into a 10-year throughput agreement containing minimum quarterly throughput commitments from HFC. As of June 30, 2017, these commitments provide minimum annualized revenues of $6 million.

Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross Refinery, for cash consideration of $278 million. In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC. As of June 20, 2017 these commitments provide minimum annualized revenues of $57 million.

- 32 -

Table of Contentsril 19,

We are a consolidated variable interest entity (“VIE”) of HFC. Therefore, the acquisitions of the crude tanks at HFC's Tulsa refinery on March 31, 2016, and Woods Cross Operating on October 1, 2016, were accounted for as transfers between entities under common control. Accordingly, this financial data has been retrospectively adjusted to include the historical results of these acquisitions for all periods presented prior to the effective dates of each acquisition. We refer to these historical results as those of our "Predecessor." See Note 1 for further discussion of these acquisitions and basis of presentation.

Agreements with HFC and Alon

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 each year, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of June 30, 2017, these agreements with HFC require minimum annualized payments to us of $322 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 Alon expiring in 2020 under which Alon 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 Alon space on our Orla to El Paso pipeline for the shipment of refined product, which expires in 2022. As of June 30, 2017, these agreements with Alon 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.

- 33 -

Table of Contentsril 19,

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the six months ended June 30, 2017 and 2016. These results have been adjusted to include the combined results of our Predecessor. See Note 1 to the Consolidated Financial Statements of HEP for discussion of the basis of this presentation



	Three Months Ended June 30,						Change from
	2017			2016			2016
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	19,432		$	19,392		$	40
Affiliates—intermediate pipelines	7,250			6,780			470
Affiliates—crude pipelines	16,919			18,581			(1,662		)
	43,601			44,753			(1,152		)
Third parties—refined product pipelines	11,647			11,434			213
	55,248			56,187			(939		)
Terminals, tanks and loading racks:
Affiliates	32,012			30,250			1,762
Third parties	4,344			4,285			59
	36,356			34,535			1,821

Affiliates—refinery processing units	17,539			4,175			13,364

Total revenues	109,143			94,897			14,246
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	34,097			29,212			4,885
Depreciation and amortization	19,945			15,712			4,233
General and administrative	2,615			2,863			(248		)
	56,657			47,787			8,870
Operating income	52,486			47,110			5,376
Other income (expense):
Equity in earnings of equity method investments	4,053			3,623			430
Interest expense, including amortization	(13,748		)	(11,276		)	(2,472		)
Interest income	103			112			(9		)
Gain on sale of assets and other	89			—			89
	(9,503		)	(7,541		)	(1,962		)
Income before income taxes	42,983			39,569			3,414
State income tax expense	(127		)	(54		)	(73		)
Net income	42,856			39,515			3,341
Allocation of net loss to Predecessor	—			1,960			(1,960		)
Allocation of net income attributable to noncontrolling interests	(1,521		)	(2,355		)	834
Net income attributable to the partners	41,335			39,120			2,215
General partner interest in net income attributable to the partners ⁽¹⁾	(18,328		)	(12,677		)	(5,651		)
Limited partners’ interest in net income	$	23,007		$	26,443		$	(3,436	)
Limited partners’ earnings per unit—basic and diluted ⁽¹⁾	$	0.36		$	0.45		$	(0.09	)
Weighted average limited partners’ units outstanding	64,086			58,865			5,221
EBITDA ⁽²⁾	$	75,052		$	66,047		$	9,005
Distributable cash flow ⁽³⁾	$	60,908		$	55,709		$	5,199

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	134,357			125,535			8,822
Affiliates—intermediate pipelines	151,683			135,165			16,518
Affiliates—crude pipelines	269,418			278,414			(8,996		)
	555,458			539,114			16,344
Third parties—refined product pipelines	71,612			74,386			(2,774		)
	627,070			613,500			13,570
Terminals and loading racks:
Affiliates	461,329			418,233			43,096
Third parties	67,657			71,415			(3,758		)
	528,986			489,648			39,338

Affiliates—refinery processing units	67,310			50,376			16,934

Total for pipelines and terminal and refiney processing unit assets (bpd)	1,223,366			1,153,524			69,842

- 34 -

Table of Contentsril 19,



	Six Months Ended June 30,						Change from
	2017			2016			2016
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	37,176		$	44,574		$	(7,398	)
Affiliates—intermediate pipelines	12,534			14,193			(1,659		)
Affiliates—crude pipelines	33,800			36,072			(2,272		)
	83,510			94,839			(11,329		)
Third parties—refined product pipelines	24,185			26,200			(2,015		)
	107,695			121,039			(13,344		)
Terminals, tanks and loading racks:
Affiliates	61,748			58,503			3,245
Third parties	8,415			8,683			(268		)
	70,163			67,186			2,977

Affiliates—refinery processing units	36,919			8,682			28,237

Total revenues	214,777			196,907			17,870
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	66,586			57,067			9,519
Depreciation and amortization	38,722			32,263			6,459
General and administrative	5,249			5,954			(705		)
	110,557			95,284			15,273
Operating income	104,220			101,623			2,597
Other income (expense):
Equity in earnings of equity method investments	5,893			6,388			(495		)
Interest expense, including amortization	(27,287		)	(21,811		)	(5,476		)
Interest income	205			224			(19		)
Loss on early extinguishment of debt	(12,225		)	—			(12,225		)
Gain (loss) on sale of assets	162			(8		)	170
	(33,252		)	(15,207		)	(18,045		)
Income before income taxes	70,968			86,416			(15,448		)
State income tax expense	(233		)	(149		)	(84		)
Net income	70,735			86,267			(15,532		)
Allocation of net loss to Predecessor	—			3,110			(3,110		)
Allocation of net income attributable to noncontrolling interests	(3,837		)	(7,282		)	3,445
Net income attributable to the partners	66,898			82,095			(15,197		)
General partner interest in net income attributable to the partners ⁽¹⁾	(35,466		)	(24,779		)	(10,687		)
Limited partners’ interest in net income	$	31,432		$	57,316		$	(25,884	)
Limited partners’ earnings per unit—basic and diluted ⁽¹⁾	$	0.49		$	0.96		$	(0.47	)
Weighted average limited partners’ units outstanding	63,602			58,761			4,841
EBITDA ⁽²⁾	$	145,160		$	135,973		$	9,187
Distributable cash flow ⁽³⁾	$	118,197		$	111,075		$	7,122

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	120,886			128,983			(8,097		)
Affiliates—intermediate pipelines	128,143			136,288			(8,145		)
Affiliates—crude pipelines	269,155			282,923			(13,768		)
	518,184			548,194			(30,010		)
Third parties—refined product pipelines	78,339			76,360			1,979
	596,523			624,554			(28,031		)
Terminals and loading racks:
Affiliates	418,365			387,628			30,737
Third parties	68,646			76,370			(7,724		)
	487,011			463,998			23,013

Affiliates—refinery processing units	65,082			46,409			18,673

Total for pipelines and terminal and refinery processing unit assets (bpd)	1,148,616			1,134,961			13,655

- 35 -

Table of Contentsril 19,



	June 30, 2017		December 31, 2016
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	16,339	$	3,657
Working capital (deficit)	$	16,591	$	(7,782	)
Total assets	$	1,867,891	$	1,884,237
Long-term debt	$	1,236,739	$	1,243,912
Partners’ equity ⁽⁵⁾	$	387,370	$	378,234

(1)

Net income attributable to the partners is 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 includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions and other priority allocations are allocated to the general partner, the remaining net income attributable to the partners is allocated to the partners based on their weighted average ownership percentage during the period.

(2)

Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to the partners plus (i) interest expense and loss on early extinguishment of debt, net of interest income, (ii) state income tax and (iii) depreciation and amortization, excluding amounts related to the Predecessor. 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,
	2017			2016			2017			2016
	(In thousands)
Net income attributable to the partners	$	41,335		$	39,120		$	66,898		$	82,095
Add (subtract):
Interest expense	12,982			10,493			25,751			20,435
Interest income	(103		)	(112		)	(205		)	(224		)
Amortization of discount and deferred debt issuance costs	766			783			1,536			1,376
Loss on early extinguishment of debt	—			—			12,225			—
State income tax expense	127			54			233			149
Depreciation and amortization	19,945			15,712			38,722			32,263
Predecessor depreciation and amortization	—			(3		)	—			(121		)
EBITDA	$	75,052		$	66,047		$	145,160		$	135,973

(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.

- 36 -

Table of Contentsril 19,



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands)
Net income attributable to the partners	$	41,335		$	39,120		$	66,898		$	82,095
Add (subtract):
Depreciation and amortization	19,945			15,712			38,722			32,263
Amortization of discount and deferred debt issuance costs	766			783			1,536			1,376
Loss on early extinguishment of debt	—			—			12,225			—
Increase (decrease) in deferred revenue related to minimum revenue commitments	1,524			1,731			2,701			(1,927		)
Maintenance capital expenditures⁽⁴⁾	(2,242		)	(2,661		)	(3,067		)	(4,322		)
Decrease in environmental liability	(313		)	(113		)	(559		)	(442		)
Decrease in reimbursable deferred revenue	(923		)	(628		)	(1,848		)	(1,155		)
Other non-cash adjustments	816			1,768			1,589			3,308
Predecessor depreciation and amortization	—			(3		)	—			(121		)
Distributable cash flow	$	60,908		$	55,709		$	118,197		$	111,075


(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.

(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, 2017 Compared with Three Months Ended June 30, 2016

Summary

Net income attributable to the partners for the second quarter was $41.3 million ($0.36 per basic and diluted limited partner unit) compared to $39.1 million ($0.45 per basic and diluted limited partner unit) for the second quarter of 2016. The increase in earnings is primarily due to increased operating income from our Woods Cross refinery processing units of $4.5 million offset by higher interest expense of $2.5 million.

Our major shippers are obligated to make deficiency payments to us if they do not exceed their minimum volume shipping obligations. Revenues for the three months ended June 30, 2017, include the recognition of $0.6 million of prior shortfalls billed to shippers in 2016 compared to revenues for the three months ended June 30, 2016, which included the recognition of $0.3 million of prior shortfalls billed to shippers in 2015. Additional net shortfall billings of $2.4 million associated with certain guaranteed shipping contracts were deferred during the three months ended June 30, 2017. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will have the necessary capacity for shipments in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.

Revenues

Revenues for the quarter were $109.1 million, an increase of $14.2 million compared to the second quarter of 2016 primarily due to revenues of $12.9 million from the Woods Cross refinery processing units. Overall pipeline volumes were up 2% compared to the three months ended June 30, 2016, largely due to an increase in intermediate pipeline shipments.

Revenues from our refined product pipelines were $31.1 million, an increase of $0.3 million compared to the second quarter of 2016, and shipments averaged 206.0 mbpd compared to 199.9 mbpd for the second quarter of 2016. Revenues and volumes both increased primarily due to higher spot sales on our UNEV pipeline, offset by lower throughput on the Alon system.

- 37 -

Table of Contentsril 19,

Revenues from our intermediate pipelines were $7.3 million, an increase of $0.5 million, on shipments averaging 151.7 mbpd compared to 135.2 mbpd for the second quarter of 2016. These volume increases were principally due to (a) 10.8 mbpd increase on HFC's Tulsa refinery ("Tulsa") interconnect lines and (b) 5.7 mbpd increase in HFC's Navajo refinery ("Navajo") intermediate lines due to increased refinery crude rate after their second quarter 2017 turnaround. These volume increases were offset by deferred revenue.

Revenues from our crude pipelines were $16.9 million, a decrease of $1.7 million, on shipments averaging 269.4 mbpd compared to 278.4 mbpd for the second quarter of 2016. Revenues decreased mainly due to a decrease in deferred revenue realized.

Revenues from terminal, tankage and loading rack fees were $36.4 million, an increase of $1.8 million compared to the second quarter of 2016. Refined products terminalled in the facilities averaged 529.0 mbpd compared to 489.6 mbpd for the second quarter of 2016. The volume and revenue increases are mainly due to increased throughput at our Tulsa tankage and loading racks, Cheyenne loading racks, and UNEV Pipeline, LLC terminals.

Revenues from refinery processing units were $17.5 million, an increase of $13.4 million on throughputs averaging 67.3 mbpd compared to 50.4 mbpd for the second quarter of 2016. This increase in revenue and volume is primarily due to the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Operations Expense

Operations (exclusive of depreciation and amortization) expense for the three months ended June 30, 2017, increased by $4.9 million compared to the three months ended June 30, 2016. The increase is mainly due to an additional $5.5 million in operating expenses from the newly acquired Woods Cross refinery processing units offset by lower maintenance project costs.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2017, increased by $4.2 million compared to the three months ended June 30, 2016. The increase is principally due to depreciation from our newly acquired Woods Cross refinery processing units.

General and Administrative

General and administrative costs for the three months ended June 30, 2017, decreased by $0.2 million compared to the three months ended June 30, 2016, mainly due to lower employee compensation expense.

Equity in Earnings of Equity Method Investments



	Three Months Ended June 30,
Equity Method Investment	2017		2016
	(in thousands)
SLC Pipeline LLC	$	906	$	1,089
Frontier Aspen LLC	1,587		938
Osage Pipe Line Company, LLC	568		1,233
Cheyenne Pipeline LLC	992		363
Total	$	4,053	$	3,623

Interest Expense

Interest expense for the three months ended June 30, 2017, totaled $13.7 million, an increase of $2.5 million compared to the three months ended June 30, 2016. The increase is due to the offering of $400 million aggregate principal amount of our 6% Senior Notes in July 2016 and a higher balance outstanding on our senior secured revolving credit facility. Our aggregate effective interest rates were 4.4% and 4.2% for the three months ended June 30, 2017 and 2016, respectively.

State Income Tax

We recorded state income tax expense of $127,000 and $54,000 for the three months ended June 30, 2017 and 2016, respectively. All tax expense is solely attributable to the Texas margin tax.

- 38 -

Table of Contentsril 19,

Results of Operations—Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

Summary

Net income attributable to Holly Energy Partners for the six months ended June 30, 2017, was $66.9 million compared to $82.1 million for the six months ended June 30, 2016. The decrease in earnings is primarily due to (a) a charge of $12.2 million related to the early redemption of our previously outstanding $300 million, 6.5% Senior Notes (the “6.5% Senior Notes”), due in 2020, (b) a reduction in pipeline revenues primarily driven by a turnaround at HFC’s Navajo refinery, (c) higher interest expense and (d) lower equity in earnings from equity method investments caused by an outage on the SLC pipeline offset by (e) earnings from our Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Revenues for the six months ended June 30, 2017, include the recognition of $2.7 million of prior shortfalls billed to shippers in 2016 as they did not exceed their minimum volume commitments within the contractual make-up period. Additional net shortfall billings of $5.1 million associated with certain guaranteed shipping contracts were deferred during the six months ended June 30, 2017. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will have the necessary capacity for shipments in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.

Revenues

Revenues for the six months ended June 30, 2017, were $214.8 million, a $17.9 million increase compared to the six months ended June 30, 2016. The increase is primarily attributable to the $27.6 million of revenue recorded for the Woods Cross refinery processing units acquired in the fourth quarter of 2016, offset by a $7.9 million decrease in revenues around assets serving HFC's Navajo refinery due to the substantial turnaround at the Navajo refinery during the first quarter of 2017. Overall pipeline volumes were down 4.5% compared to the six months ended June 30, 2016.

Revenues from our refined product pipelines were $61.4 million, a decrease of $9.4 million, on shipments averaging 199.2 mbpd compared to 205.3 mbpd for the six months ended June 30, 2016. Revenues and volumes both decreased mainly due to the turnaround at HFC's Navajo refinery in the first quarter of 2017.

Revenues from our intermediate pipelines were $12.5 million, a decrease of $1.7 million, on shipments averaging 128.1 mbpd compared to 136.3 mbpd for the six months ended June 30, 2016. These volume decreases were primarily due to the turnaround at HFC's Navajo refinery, offset by increases on both the Tulsa and Navajo interconnect lines.

Revenues from our crude pipelines were $33.8 million, a decrease of $2.3 million, on shipments averaging 269.2 mbpd compared to 282.9 mbpd for the six months ended June 30, 2016. Revenues and volumes decreased principally due to HFC's Navajo refinery turnaround in the first quarter of 2017 and a decrease in deferred revenue recognized.

Revenues from terminal, tankage and loading rack fees were $70.2 million, an increase of $3.0 million compared to the six months ended June 30, 2016. Refined products terminalled in the facilities averaged 487.0 mbpd compared to 464.0 mbpd for the six months ended June 30, 2016. The volume and revenue increases are mainly due to our Tulsa crude tanks acquired on the last day of the first quarter of 2016 offset by the transfer of the El Paso terminal to HollyFrontier in the first quarter of 2016.

Revenues from refinery processing units were $36.9 million, an increase of $28.2 million on throughputs averaging 65.1 mbpd compared to 46.4 mbpd for the six months ended June 30, 2016. The increases in revenue and volume is primarily due to the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Operations Expense

Operations expense (exclusive of depreciation and amortization) for the six months ended June 30, 2017, increased by $9.5 million compared to the six months ended June 30, 2016. The increase is primarily due to operating expenses for our newly acquired Woods Cross refinery processing units partially offset by lower environmental costs and maintenance project expenses.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2017, increased by $6.5 million compared to the six months ended June 30, 2016. The increase is mainly due to depreciation from the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

- 39 -

Table of Contentsril 19,

General and Administrative

General and administrative costs for the six months ended June 30, 2017, decreased $0.7 million compared to the six months ended June 30, 2016, mainly due to decreased incentive compensation.

Equity in Earnings of Equity Method Investments

In the first quarter of 2017, the SLC Pipeline was proactively shut down for a period of 28 days due to land movement along the right-of-way at Mountain Green, Utah. This not only impacted shipments of crude on the SLC Pipeline, but also crude shipments on the connected Frontier Pipeline. This shutdown is primarily responsible for a $1.4 million decrease in our equity in earnings related to SLC Pipeline LLC and Frontier Aspen LLC, shown below in the summary chart, which displays all our earnings in equity method investments:



	Six Months Ended June 30,
Equity Method Investments	2017		2016
	(in thousands)
SLC Pipeline LLC	$	1,024	$	2,114
Frontier Aspen, LLC	2,151		2,463
Osage Pipe Line Company, LLC	770		1,448
Cheyenne Pipeline LLC	1,948		363
Total	$	5,893	$	6,388

Interest Expense

Interest expense for the six months ended June 30, 2017, totaled $27.3 million, an increase of $5.5 million compared to the six months ended June 30, 2016. The increase is primarily due to the $400 million 6% Senior Notes issued July 19, 2016, and a higher average balance outstanding on the Credit Agreement. Our aggregate effective interest rates were 4.3% and 4.2% for the six months ended June 30, 2017 and 2016, 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 $233,000 and $149,000 for the six months ended June 30, 2017 and 2016, respectively. All tax expense is solely attributable to the Texas margin tax.

LIQUIDITY AND CAPITAL RESOURCES

Overview

During the six months ended June 30, 2017, we received advances totaling $479.0 million and repaid $189.0 million, resulting in a net increase of $290.0 million under the Credit Agreement and an outstanding balance of $843.0 million at June 30, 2017. We have no letters of credit outstanding under the Credit Agreement at June 30, 2017, and the available capacity under the Credit Agreement is $357.0 million at June 30, 2017. 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.

- 40 -

Table of Contentsril 19,

On January 4, 2017, we redeemed the $300 million aggregate principal amount of 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.

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, 2017, HEP issued 1,538,452 units under this program, providing approximately $52.4 million in net 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, 2017, HEP has issued 2,241,907 units under this program, providing $77.1 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 February and May, we paid regular quarterly cash distributions of $0.6075 and $0.6200, respectively, on all units in an aggregate amount of $112.2 million including $32.2 million of incentive distribution payments to our general partner.

Cash and cash equivalents increased by $12.7 million during the six months ended June 30, 2017. The cash flows provided by operating activities of $113.6 million were greater than the cash flows used for financing activities of $82.7 million and investing activities of $18.2 million. Working capital increased by $24.4 million to $16.6 million at June 30, 2017, from a negative $7.8 million at December 31, 2016.

Cash Flows—Operating Activities

Cash flows from operating activities increased by $2.3 million from $111.3 million for the six months ended June 30, 2016, to $113.6 million for the six months ended June 30, 2017. This increase is due principally to higher cash receipts for services performed partially offset by higher payments for interest and operating expenses in the six months ended June 30, 2017, as compared to the prior year.

Cash Flows—Investing Activities

Cash flows used for investing activities were $18.2 million for the six months ended June 30, 2017, compared to $116.4 million for the six months ended June 30, 2016, a decrease of $98.1 million. During the six months ended June 30, 2017 and 2016, we invested $20.5 million and $32.7 million in additions to properties and equipment, respectively. During the six months ended June 30, 2017 and 2016, we also received $1.7 million and $1.5 million for distributions in excess of equity in earnings of equity investments, respectively. Additionally, we have retrospectively adjusted our historical financial results for the six months ended June 30, 2016, to include the Woods Cross refinery processing units as we are under common control of HFC. Therefore, the cash flows from investing activities reflect outflows of $42.7 million for the Woods Cross refinery processing units and $42.5 million for the purchase of a 50% interest in the Cheyenne Pipeline during the six months ended June 30, 2016.

Cash Flows—Financing Activities

Cash flows used for financing activities were $82.7 million for the six months ended June 30, 2017, compared to $5.1 million for the six months ended June 30, 2016, an increase of $77.6 million. 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 also received proceeds of $52.6 million from the issuance of common units under our continuous offering program. Additionally, we paid $112.2 million in regular quarterly cash distributions to our general and limited partners and $3.5 million to our noncontrolling interest. During the six months ended June 30, 2016, we paid $39.5 million for the crude oil tanks located at HFC’s Tulsa refinery acquired in March 2016. We received $239.0 million and repaid $165.0 million in advances under the Credit Agreement. We paid $91.1 million in regular quarterly cash distributions to our general and limited partners, distributed $2.5 million to our noncontrolling interest, and paid $3.1 million in deferred financing charges to amend our credit agreement. We also received proceeds of $13.7 million from the issuance of common units under our continuous offering program. In addition, we received $45.7 million for Woods Cross processing units expenditures from HFC.

- 41 -

Table of Contentsril 19,

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 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. “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. The 2017 capital budget is comprised of $9 million for maintenance capital expenditures and approximately $30 million for expansion capital expenditures. We expect the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks, and enhanced blending capabilities at our racks. 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 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 to date.

Credit Agreement

- 42 -

Table of Contentsril 19,

Senior Notes

On January 4, 2017, we redeemed the $300 million aggregate principal amount of our 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.

We have $400 million in aggregate principal amount of 6% Senior Notes due in 2024. We used the net proceeds from our offering of the 6% Senior Notes to repay indebtedness under our revolving credit agreement.

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

Long-term Debt

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



	June 30, 2017			December 31, 2016
	(In thousands)
Credit Agreement	$	843,000		$	553,000

6% Senior Notes
Principal	400,000			400,000
Unamortized debt issuance costs	(6,261		)	(6,607		)
	393,739			393,393
6.5% Senior Notes
Principal	—			300,000
Unamortized discount and debt issuance costs	—			(2,481		)
	—			297,519

Total long-term debt	$	1,236,739		$	1,243,912

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, 2017 and 2016. Historically, the PPI has increased an average of 0.2% annually over the past five calendar years, including a decrease of 1.0% in 2016.

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.

- 43 -

Table of Contentsril 19,

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. We believe our operations are in substantial compliance with applicable environmental laws and regulations. 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.

We have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon 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, 2017, we have an accrual of $6.5 million that relates to environmental clean-up projects for which we have assumed liability or for which the indemnity provided for by 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, 2016. 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. There have been no changes to these policies in 2017. 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.

Accounting Pronouncements Adopted During the Periods Presented

Earnings Per Unit

In April 2015, an accounting standard update was issued requiring changes to the allocation of the earnings or losses of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating historical earnings per unit. We adopted this standard as of January 1, 2016. In connection with the dropdown of assets from HFC’s Tulsa refinery on March 31, 2016, and the purchase of HFC’s Woods Cross refinery units on October 1, 2016, we reduced net income by $2.0 million and $3.1 million for the three and six months ended June 30, 2016, respectively. These reductions had no impact on the historical earnings per unit as they were allocated to the general partner.

- 44 -

Table of Contentsril 19,

Share-Based Compensation

Accounting Pronouncements Not Yet Adopted

Revenue Recognition

Business Combinations

Financial Assets and Liabilities

Leases

RISK MANAGEMENT

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of June 30, 2017, we had two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150.0 million of Credit Agreement advances. The swaps effectively converted $150.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.25% as of June 30, 2017, which equaled an effective interest rate of 2.99%. Both of these swap contracts matured on July 31, 2017.

We review publicly available information on our counterparties in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. These counterparties are large financial institutions. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their respective commitments.

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, 2017, we had an outstanding principal balance of $400 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, 2017, the fair value of our 6% Senior Notes was $418.0 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6% Senior Notes at June 30, 2017, would result in a change of approximately $12.6 million in the fair value of the underlying 6% Senior Notes.

- 45 -

Table of Contentsril 19,

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At June 30, 2017, borrowings outstanding under the Credit Agreement were $843 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.


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, 2016. We utilize derivative instruments to hedge our interest rate exposure, as discussed under “Risk Management.”

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, 2017, 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.

- 46 -

Table of Contentsril 19,

PART II. OTHER INFORMATION


Item 1.	Legal Proceedings

We are a party to various legal and regulatory proceedings, which we believe will not have a material 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, 2016. In addition to the other information set forth in this quarterly report, you should consider carefully the factors discussed in our 2016 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2016 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 49 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of the Quarterly Report on Form 10-Q.

- 47 -

Table of Contentsril 19,

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, 2017		/s/ Richard L. Voliva III
		Richard L. Voliva III
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Date: August 2, 2017		/s/ Kenneth P. Norwood
		Kenneth P. Norwood
		Vice President and Controller (Principal Accounting Officer)

- 48 -

Table of Contentsril 19,

Exhibit Index



Exhibit Number		Description

3.1		First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.2		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated February 28, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
3.3		Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., as amended, dated July 6, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
3.4		Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated April 11, 2008 (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K dated April 15, 2008, File No. 1-32225).
3.5		Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated January 16, 2013 (incorporated by reference to Exhibit 3.1 of Registrant’s Current Report on Form 8-K dated January 16, 2013, File No. 1-32225).
3.6		Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated June 13, 2016 (incorporated by reference to Exhibit 3.1 of Registrant’s Current Report on Form 8-K dated June 15, 2016, File No. 1-32225).
3.7		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 its quarterly period ended June 30, 2004, File No. 1-32225).
3.8		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).
3.9		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).
3.10		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 dated May 3, 2011, File No. 1-32225).
3.11		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*		Second Supplemental Indenture, dated July 26, 2017, by and among Holly Energy Holdings LLC, HEP Cheyenne Shortline LLC, the Registrant, Holly Energy Finance Corp., the other guarantors therein and U.S. Bank, National Association, as trustee.
10.1		Amendment to Amended and Restated Master Tolling Agreement (Operating Assets), dated as of January 1, 2017, by and among Holly Energy Partners-Operating, L.P., HollyFrontier El Dorado Refining LLC and HollyFrontier Woods Cross Refining LLC. (incorporated by reference to Exhibit 10.8 of the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2017, File No. 1-32225).
10.2		Amendment to Master Tolling Agreement, dated as of January 1, 2017, by and among Holly Energy Partners-Operating, L.P., HollyFrontier El Dorado Refining LLC and HollyFrontier Woods Cross Refining LLC. (incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2017, File No. 1-32225).
10.3		Third Amended and Restated Credit Agreement, dated July 26, 2017, by and among the Registrant, certain of its affiliates as guarantors, Wells Fargo Bank, National Association and certain other leaders party thereto (incorporated by reference to Exhibit 10.1 of the Registrants’ Current Report on Form 8-K, dated July 31, 2017,File no. 1-32225).
10.4*		Amendment to Equity Distribution Agreement, dated as of July 28, 2017, by and among the Registrant, HEP Logistics Holdings, L.P., Holly Logistics Services, L.L.C. and Citigroup Global Markets Inc., Goldman, Sachs & Co., and Merrill Lynch, Pierce, Fenner & Smith Incorporated.
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.

- 49 -

Table of Contentsril 19,



101++		The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, 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.

- 50 -

HOLLY ENERGY PARTNERS LP - FORM 10-Q - August 2, 2017

Attached files

HOLLY ENERGY PARTNERS LP Reports