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 ~~September~~June 30, ~~2017~~2021



¨ ☐			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~~
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)

Securities registered pursuant to 12(b) of the Securities Exchange Act of 1934:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Limited Partner Units

HEP

New York Stock Exchange

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

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

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

Large accelerated filer

ý☒

Accelerated filer

¨☐

Non-accelerated filer

¨☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

☒

The number of the registrant’s outstanding common units at ~~October 31, 2017,~~July 30, 2021, was ~~64,318,955.~~105,440,201.

Table of ~~Contentsril~~ 19,

HOLLY ENERGY PARTNERS, L.P.

INDEX

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Table of ~~Contentsril~~ 19,

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, ~~those~~statements regarding funding of capital expenditures and distributions, distributable cash flow coverage and leverage targets, and statements 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.~~operations are intended to identify forward-looking statements. 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:

•the extraordinary market environment and effects of the COVID-19 pandemic, including a significant decline in demand for refined petroleum products in markets we serve;

•(i) our ability to successfully close the Sinclair acquisition, which requires certain regulatory approvals (including clearance by antitrust authorities); (ii) disruption the Sinclair acquisition may cause to customers, vendors, business partners and our ongoing business; (iii) once closed, our ability to integrate the operations of Sinclair with our existing operations and fully realize the expected synergies of the Sinclair acquisition on the expected timeline; and (iv) legal proceedings that may be instituted against us or HollyFrontier Corporation (“HFC”) following the announcement of the Sinclair acquisition;

•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;~~terminals and refinery processing units;

•the economic viability of ~~HollyFrontier Corporation, Alon USA, Inc.~~HFC, our other customers and our joint ventures’ other ~~customers;~~customers, including any refusal or inability of our or our joint ventures’ customers or counterparties to perform their obligations under their contracts;

•the demand for refined petroleum products in the 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 temporary or permanent reductions in production or shutdowns at refineries utilizing our ~~pipeline and~~pipelines, terminal facilities and refinery processing units, due to reasons such as infection in the workforce, in response to reductions in demand or ~~containing our processing units;~~lower gross margins due to the economic impact of the COVID-19 pandemic, and any potential asset impairments resulting from such actions;

•the effects of current and future government regulations and ~~policies;~~policies, including the effects of current and future restrictions on various commercial and economic activities in response to the COVID-19 pandemic;

•delay by government authorities in issuing permits necessary for our business or our capital projects;

•our and our joint venture partners’ ability to complete and maintain operational efficiency in carrying out routine operations and capital construction projects;

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

•general economic ~~conditions;~~conditions, including uncertainty regarding the timing, pace and extent of an economic recovery in the United States;

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

- 3 -

Table of 19,

•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. You should not put any undue reliance on any forward-looking statements. 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~~,2020, and in this Quarterly Report on Form 10-Q, and in connection with the discussion in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations” and in “Risk Factors.~~Operations.” 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.

- 4 -

Table of ~~Contentsril~~ 19,

PART I. FINANCIAL INFORMATION


~~Item 1.~~	~~Financial Statements~~

Item 1.Financial Statements

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)


	September 30, 2017			December 31, 2016				June 30, 2021		December 31, 2020
	(Unaudited)							(Unaudited)
ASSETS							ASSETS
Current assets:							Current assets:
Cash and cash equivalents	$	7,476		$	3,657
Cash and cash equivalents (Cushing Connect VIEs: $14,055 and $18,259, respectively)							Cash and cash equivalents (Cushing Connect VIEs: $14,055 and $18,259, respectively)	$	19,561	$	21,990
Accounts receivable:							Accounts receivable:
Trade	7,330			7,846			Trade	14,749		14,543
Affiliates	42,753			42,562			Affiliates	46,323		47,972
	50,083			50,408				61,072		62,515
Prepaid and other current assets	2,295			2,888			Prepaid and other current assets	9,277		9,487
Total current assets	59,854			56,953			Total current assets	89,910		93,992

Properties and equipment, net	1,307,093			1,328,395
Transportation agreements, net	61,644			66,856
Properties and equipment, net (Cushing Connect VIEs: $84,263 and $47,801, respectively)							Properties and equipment, net (Cushing Connect VIEs: $84,263 and $47,801, respectively)	1,430,311		1,450,685
Operating lease right-of-use assets, net							Operating lease right-of-use assets, net	2,724		2,979
Net investment in leases							Net investment in leases	211,550		166,316
Intangible assets, net							Intangible assets, net	80,311		87,315
Goodwill	256,498			256,498			Goodwill	223,650		234,684
Equity method investments	163,873			165,609
Equity method investments (Cushing Connect VIEs: $37,988 and $39,456, respectively)							Equity method investments (Cushing Connect VIEs: $37,988 and $39,456, respectively)	117,436		120,544
Other assets	16,880			9,926			Other assets	16,930		11,050
Total assets	$	1,865,842		$	1,884,237		Total assets	$	2,172,822	$	2,167,565

LIABILITIES AND EQUITY							LIABILITIES AND EQUITY
Current liabilities:							Current liabilities:
Accounts payable:							Accounts payable:
Trade	$	13,584		$	10,518
Trade (Cushing Connect VIEs: $9,994 and $14,076, respectively)							Trade (Cushing Connect VIEs: $9,994 and $14,076, respectively)	$	25,591	$	28,280
Affiliates	9,559			16,424			Affiliates	14,964		18,120
	23,143			26,942				40,555		46,400

Accrued interest	5,527			18,069			Accrued interest	10,869		10,892
Deferred revenue	14,827			11,102			Deferred revenue	10,569		11,368
Accrued property taxes	7,487			5,397			Accrued property taxes	5,057		3,992
Current operating lease liabilities							Current operating lease liabilities	795		875
Current finance lease liabilities							Current finance lease liabilities	3,755		3,713
Other current liabilities	3,492			3,225			Other current liabilities	2,943		2,505
Total current liabilities	54,476			64,735			Total current liabilities	74,543		79,745

Long-term debt	1,245,066			1,243,912			Long-term debt	1,362,570		1,405,603
Noncurrent operating lease liabilities							Noncurrent operating lease liabilities	2,303		2,476
Noncurrent finance lease liabilities							Noncurrent finance lease liabilities	66,434		68,047
Other long-term liabilities	15,477			16,445			Other long-term liabilities	11,913		12,905
Deferred revenue	46,405			47,035			Deferred revenue	32,645		40,581

Class B unit	42,412			40,319			Class B unit	54,637		52,850

Equity:							Equity:
Partners’ equity:							Partners’ equity:
Common unitholders (64,318,955 and 62,780,503 units issued and outstanding at September 30, 2017 and December 31, 2016, respectively)	520,709			510,975
General partner interest (2% interest)	(149,994		)	(132,832		)
Accumulated other comprehensive income	—			91
Total partners’ equity	370,715			378,234
Noncontrolling interest	91,291			93,557
Common unitholders (105,440 units issued and outstanding at June 30, 2021 and December 31, 2020)							Common unitholders (105,440 units issued and outstanding at June 30, 2021 and December 31, 2020)	425,218		379,292
Noncontrolling interests							Noncontrolling interests	142,559		126,066
Total equity	462,006			471,791			Total equity	567,777		505,358
Total liabilities and equity	$	1,865,842		$	1,884,237		Total liabilities and equity	$	2,172,822	$	2,167,565

See accompanying notes.

- 5 -

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,
	2021		2020		2021		2020
Revenues:
Affiliates	$	99,142	$	95,563	$	201,068	$	196,991
Third parties	27,093		19,244		52,350		45,670
	126,235		114,807		253,418		242,661
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	42,068		34,737		83,433		69,718
Depreciation and amortization	25,003		25,034		50,068		49,012
General and administrative	2,847		2,535		5,815		5,237
Goodwill impairment	0		0		11,034		0
	69,918		62,306		150,350		123,967
Operating income	56,317		52,501		103,068		118,694

Other income (expense):
Equity in earnings of equity method investments	3,423		2,156		5,186		3,870
Interest expense	(13,938)		(13,779)		(27,178)		(31,546)
Interest income	6,614		2,813		13,162		5,031
Loss on early extinguishment of debt	0		0		0		(25,915)
Gain on sales-type leases	27		33,834		24,677		33,834
Gain on sale of assets and other	5,415		468		5,917		974
	1,541		25,492		21,764		(13,752)
Income before income taxes	57,858		77,993		124,832		104,942
State income tax expense	(27)		(39)		(64)		(76)
Net income	57,831		77,954		124,768		104,866
Allocation of net income attributable to noncontrolling interests	(2,086)		(1,484)		(4,626)		(3,535)
Net income attributable to the partners	55,745		76,470		120,142		101,331
Limited partners’ per unit interest in earnings—basic and diluted	$	0.53	$	0.73	$	1.14	$	0.96
Weighted average limited partners’ units outstanding	105,440		105,440		105,440		105,440

Three Months Ended
September 30, Nine Months Ended
September 30,
2017
2016 ⁽¹⁾
2017
2016 ⁽¹⁾
Revenues:
Affiliates $ 95,138
$ 77,398
$ 277,316
$ 239,423
Third parties 15,226
15,212
47,826
50,094
110,364
92,610
325,142
289,517
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) 35,998
32,101
102,584
89,168
Depreciation and amortization 19,007
18,920
57,729
51,183
General and administrative 3,623
2,664
8,872
8,618
58,628
53,685
169,185
148,969
Operating income 51,736
38,925
155,957
140,548

Other income (expense):
Equity in earnings of equity method investments 5,072
3,767
10,965
10,155
Interest expense (14,072 ) (14,447 ) (41,359 ) (36,258 )
Interest income 101
108
306
332
Loss on early extinguishment of debt —
—
(12,225 ) —
Gain on sale of assets and other 155
112
317
104
(8,744 ) (10,460 ) (41,996 ) (25,667 )
Income before income taxes 42,992
28,465
113,961
114,881
State income tax benefit (expense) 69
(61 ) (164 ) (210 )
Net income 43,061
28,404
113,797
114,671
Allocation of net loss attributable to Predecessor —
7,547
—
10,657
Allocation of net income attributable to noncontrolling interests (990 ) (1,166 ) (4,827 ) (8,448 )
Net income attributable to the partners 42,071
34,785
108,970
116,880
General partner interest in net income attributable to the partners 419
(15,222 ) (35,047 ) (40,001 )
Limited partners’ interest in net income $ 42,490
$ 19,563
$ 73,923
$ 76,879
Limited partners’ per unit interest in earnings—basic and diluted $ 0.66
$ 0.33
$ 1.16
$ 1.29
Weighted average limited partners’ units outstanding 64,319
59,223
63,845
58,895

~~(1) Retrospectively adjusted as described~~Net income and comprehensive income are the same in ~~Note 1.~~

all periods presented.

See accompanying notes.

~~HOLLY ENERGY PARTNERS, L.P.~~

~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~(Unaudited)~~

~~(In thousands)~~

- 6 -

Three Months Ended
September 30, Nine Months Ended
September 30,
2017
2016 ⁽¹⁾
2017
2016⁽¹⁾
Net income $ 43,061
$ 28,404
$ 113,797
$ 114,671

Other comprehensive income:
Change in fair value of cash flow hedging instruments 1
201
88
(737 )
Reclassification adjustment to net income on partial settlement of cash flow hedge (64 ) 95
(179 ) 438
Other comprehensive income (loss) (63 ) 296
(91 ) (299 )
Comprehensive income before noncontrolling interest 42,998
28,700
113,706
114,372
Allocation of net loss attributable to Predecessor —
7,547
—
10,657
Allocation of comprehensive income to noncontrolling interests (990 ) (1,166 ) (4,827 ) (8,448 )
Comprehensive income attributable to Holly Energy Partners $ 42,008
$ 35,081
$ 108,879
$ 116,581

~~(1) Retrospectively adjusted as described in Note 1.~~

~~See accompanying notes.~~

Table of ~~Contentsril~~ 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

Nine Months Ended
September 30,
2017
2016 ⁽¹⁾
Cash flows from operating activities
Net income $ 113,797
$ 114,671
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 57,729
51,183
(Gain) loss on sale of assets (269 ) (121 )
Amortization of deferred charges 2,317
2,294
Amortization of restricted and performance units 1,908
1,865
Earnings distributions greater (less) than income from equity investments 513
(1,370 )
Loss on early extinguishment of debt 12,225
—
(Increase) decrease in operating assets:
Accounts receivable—trade 516
1,521
Accounts receivable—affiliates (191 ) 2,971
Prepaid and other current assets 593
814
Increase (decrease) in operating liabilities:
Accounts payable—trade 3,393
(5,757 )
Accounts payable—affiliates (6,866 ) 1,589
Accrued interest (12,543 ) 441
Deferred revenue 3,096
6,288
Accrued property taxes 2,090
3,199
Other current liabilities (99 ) (1,020 )
Other, net (750 ) (594 )
Net cash provided by operating activities 177,459
177,974

Cash flows from investing activities
Additions to properties and equipment (30,675 ) (48,224 )
Purchase of Woods Cross refinery processing units —
(47,891 )
Purchase of interest in Cheyenne Pipeline —
(42,550 )
Proceeds from sale of assets 794
210
Distributions in excess of equity in earnings of equity investments 1,224
1,685
Other —
(351 )
Net cash used for investing activities (28,657 ) (137,121 )

Cash flows from financing activities
Borrowings under credit agreement 628,000
310,500
Repayments of credit agreement borrowings (431,000 ) (642,500 )
Proceeds from issuance of Senior Notes 101,750
394,000
Redemption of 6.5% Senior Notes (309,750 ) —
Proceeds from issuance of common units 52,285
22,791
Distributions to HEP unitholders (171,560 ) (138,798 )
Distributions to noncontrolling interest (5,000 ) (3,750 )
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 —
55,027
Contributions from general partner 1,072
470
Purchase of units for incentive grants —
(784 )
Deferred financing costs (9,453 ) (3,930 )
Other (1,224 ) (939 )
Net cash used by financing activities (144,983 ) (48,658 )

Cash and cash equivalents
Increase (decrease) for the period 3,819
(7,805 )
Beginning of period 3,657
15,013
End of period $ 7,476
$ 7,208

~~(1) Retrospectively adjusted as described in Note 1.~~


	Six Months Ended June 30,
	2021		2020
Cash flows from operating activities
Net income	$	124,768	$	104,866
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	50,068		49,012
Gain on sale of assets	(5,586)		(797)
Loss on early extinguishment of debt	0		25,915
Gain on sales-type leases	(24,677)		(33,834)
Goodwill impairment	11,034		0
Amortization of deferred charges	2,229		1,641
Equity-based compensation expense	1,210		980
Equity in earnings of equity method investments, net of distributions	0		(1,298)
(Increase) decrease in operating assets:
Accounts receivable—trade	1,726		3,803
Accounts receivable—affiliates	1,649		(131)
Prepaid and other current assets	825		216
Increase (decrease) in operating liabilities:
Accounts payable—trade	3,068		(4,959)
Accounts payable—affiliates	(3,157)		(9,452)
Accrued interest	(23)		(2,523)
Deferred revenue	(2,176)		(2,378)
Accrued property taxes	1,065		1,727
Other current liabilities	438		669
Other, net	(353)		1,137
Net cash provided by operating activities	162,108		134,594

Cash flows from investing activities
Additions to properties and equipment	(59,375)		(30,740)
Investment in Cushing Connect JV Terminal	0		(2,400)
Proceeds from sale of assets	7,343		816
Distributions in excess of equity in earnings of equity investments	3,107		470
Net cash used for investing activities	(48,925)		(31,854)

Cash flows from financing activities
Borrowings under credit agreement	141,000		168,000
Repayments of credit agreement borrowings	(184,500)		(138,500)
Redemption of senior notes	0		(522,500)
Proceeds from issuance of debt	0		500,000
Contributions from general partner	0		435
Contributions from noncontrolling interests	17,593		13,263
Distributions to HEP unitholders	(75,356)		(102,979)
Distributions to noncontrolling interests	(5,872)		(4,000)
Payments on finance leases	(1,747)		(1,972)
Deferred financing costs	(6,661)		(8,714)

Units withheld for tax withholding obligations	(69)		(147)
Net cash used by financing activities	(115,612)		(97,114)

Cash and cash equivalents
Increase (decrease) for the period	(2,429)		5,626
Beginning of period	21,990		13,287
End of period	$	19,561	$	18,913

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$25,072		$32,118

See accompanying notes.

- 7 -

Table of ~~Contentsril~~ 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF EQUITY

(Unaudited)

(In thousands)


	Common Units		Noncontrolling Interests		Total Equity

Balance December 31, 2020	$	379,292	$	126,066	$	505,358
Contributions from noncontrolling interest	—		9,746		9,746

Distributions to HEP unitholders	(38,328)		—		(38,328)
Distributions to noncontrolling interests	—		(3,819)		(3,819)

Equity-based compensation	683		—		683
Class B unit accretion	(893)		—		(893)
Other	(68)		—		(68)
Net income	65,290		1,647		66,937
Balance March 31, 2021	$	405,976	$	133,640	$	539,616
Contributions from noncontrolling interest	—		9,780		9,780
Distributions to HEP unitholders	(37,028)		—		(37,028)
Distributions to noncontrolling interest	—		(2,053)		(2,053)
Equity-based compensation	527		—		527
Class B unit accretion	(894)		—		(894)
Other	(2)		—		(2)
Net income	56,639		1,192		57,831
Balance June 30, 2021	$	425,218	$	142,559	$	567,777

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 52,285
—
—
—
52,285
Contribution from HFC —
1,072
—
—
1,072
Distribution to HFC for acquisition

—
(103 ) —
—
(103 )
Distributions to HEP unitholders (118,424 ) (53,136 ) —
—
(171,560 )
Distributions to noncontrolling interest —
—
—
(5,000 ) (5,000 )
Amortization of restricted and performance units 1,908
—
—
—
1,908
Class B unit accretion (2,051 ) (42 ) —
—
(2,093 )
Net income 76,016
35,047
—
2,734
113,797
Other comprehensive income —
—
(91 ) —
(91 )
Balance September 30, 2017 $ 520,709
$ (149,994 ) $ —
$ 91,291
$ 462,006


	Common Units		Noncontrolling Interests		Total Equity

Balance December 31, 2019	$	381,103	$	106,655	$	487,758
Contributions from noncontrolling interest	—		7,304		7,304
Distributions to HEP unitholders	(68,519)		—		(68,519)
Distributions to noncontrolling interests	—		(3,000)		(3,000)
Equity-based compensation	506		—		506
Class B unit accretion	(835)		—		(835)
Other	208		—		208
Net income	25,696		1,216		26,912
Balance March 31, 2020	$	338,159	$	112,175	$	450,334
Contributions from noncontrolling interest	—		5,959		5,959
Distributions to HEP unitholders	(34,460)		—		(34,460)
Distributions to noncontrolling interest	—		(1,000)		(1,000)
Equity-based compensation	474		—		474
Class B unit accretion	(835)		—		(835)
Other	80		—		80
Net income	77,305		649		77,954
Balance June 30, 2020	$	380,723	$	117,783	$	498,506

See accompanying notes.

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Table of ~~Contentsril~~ 19,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


~~Note 1:~~	~~Description of Business and Presentation of Financial Statements~~

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~~partnership. As of June 30, 2021, HollyFrontier Corporation (“HFC”) and its subsidiaries ~~as of September 30, 2017.~~own a 57% limited partner interest and the non-economic general partner interest in HEP. We commenced operations on July 13, 2004, upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

On October 31, 2017, we closed the restructuring transaction set forth in the definitive agreement with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics are canceled, and HEP Logistics' 2% general partner interest in HEP is converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HFC agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration are eligible to receive distributions. As of October 31, 2017, HFC held approximately 59.6 million HEP common units, representing approximately 59% of the outstanding common units. As a result of this transaction, no distributions will be made on the general partner interest after October 31, 2017.

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 of HFC and other refineries in the Mid-Continent, Southwest and Northwest regions of the United ~~States and Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. As of September 30, 2017,~~States. Additionally, we ~~owned~~own a 75% interest in UNEV Pipeline, LLC (“UNEV”~~), a 50% interest in Frontier Aspen LLC (“Frontier Aspen”~~), a 50% interest in Osage Pipe Line Company, LLC (“Osage”), a 50% interest in Cheyenne Pipeline LLC, and a ~~25%~~50% interest in ~~SLC~~Cushing Connect Pipeline ~~LLC (“SLC Pipeline”).~~& Terminal LLC.

On June 1, 2020, HFC announced plans to permanently cease petroleum refining operations at its Cheyenne Refinery (the “Cheyenne Refinery”) and to convert certain assets at that refinery to renewable diesel production. HFC subsequently began winding down petroleum refining operations at the Cheyenne Refinery on August 3, 2020.

On February 8, 2021, HEP and HFC finalized and executed new agreements for HEP’s Cheyenne assets with the following terms, in each case effective January 1, 2021: (1) a ten-year lease with 2 five-year renewal option periods for HFC’s use of certain HEP tank and rack assets in the Cheyenne Refinery to facilitate renewable diesel production with an annual lease payment of approximately $5 million, (2) a five-year contango service fee arrangement that will utilize HEP tank assets inside the Cheyenne Refinery where HFC will pay a base tariff to HEP for available crude oil storage and HFC and HEP will split any profits generated on crude oil contango opportunities and (3) a $10 million one-time cash payment from HFC to HEP for the termination of the existing minimum volume commitment.

On April 1, 2021, we sold our 156-mile, 6-inch refined product pipeline that connected HFC’s Navajo Refinery to terminals in El Paso for gross proceeds of $7.0 million and recognized a gain on sale of $5.3 million.

We operate in ~~two~~2 reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note ~~13.~~15.

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

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2020. 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.~~2021.

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.

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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~~

Goodwill and Long-Lived Assets

Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Our goodwill impairment testing first entails a comparison of our reporting unit fair values relative to their respective carrying values, including goodwill. If carrying value exceeds the estimated fair value for a reporting unit, we measure goodwill impairment as the excess of the carrying amount of the reporting unit over the estimated fair value of the reporting unit.

Indicators of goodwill and long-lived asset impairment

The changes in our new agreements with HFC related to our Cheyenne assets resulted in an increase in the net book value of our Cheyenne reporting unit due to sales-type lease accounting, which led us to determine indicators of potential goodwill impairment for our Cheyenne reporting unit were present.

The estimated fair value of our Cheyenne reporting unit was derived using a combination of income and market approaches. The income approach reflects expected future cash flows based on anticipated gross margins, operating costs, and capital expenditures. The market approaches include both the guideline public company and guideline transaction methods. Both methods utilize pricing multiples derived from historical market transactions of other like-kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs). See Note 5 for further discussion of Level 3 inputs.

Our interim impairment testing of our Cheyenne reporting unit goodwill identified an impairment charge of $11.0 million, which was recorded in the three months ended March 31, 2021.

We evaluate long-lived assets, including finite-lived intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value.

Revenue Recognition

Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majority of our contracts with customers meet the definition of a ~~business between entities under common control to be accounted for as though the transfer occurred as~~lease since (1) performance of the ~~beginning~~contracts is dependent on specified property, plant, or equipment and (2) it is unlikely that one or more parties other than the customer will take more than a minor amount of the ~~period of transfer, and prior period financial statements and financial information are retrospectively adjusted~~output associated with the specified property, plant, or equipment. Prior to ~~include~~ the ~~historical results and assets~~adoption of the ~~acquisitions~~new lease standard (see below), we bifurcated the consideration received between lease and service revenue. The new lease standard allows the election of a practical expedient whereby a lessor does not have to separate non-lease (service) components from ~~HFC~~lease components under certain conditions. The majority of our contracts meet these conditions, and we have made this election for ~~all periods presented~~those contracts. Under this practical expedient, we treat the combined components as a single performance obligation in accordance with Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09, if the non-lease (service) component is the dominant component. If the lease component is the dominant component, we treat the combined components as a lease in accordance with ASC 842, which largely codified ASU 2016-02.

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

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

In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future

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shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize these deficiency payments in revenue when we do not expect we will be required to satisfy these performance obligations in the future based on the pattern of rights projected to be exercised by the customer. During the six months ended June 30, 2021 and 2020, we recognized $6.9 million and $12.6 million, respectively, of these deficiency payments in revenue, of which $0.5 million and $0.7 million, respectively, related to deficiency payments billed in prior periods.

We have other cost reimbursement provisions in our throughput / storage agreements providing that customers (including HFC) reimburse us for certain costs. Such reimbursements are recorded as revenue or deferred revenue depending on the nature of the cost. Deferred revenue is recognized over the remaining contractual term of the related throughput agreement.

Leases

We adopted ASC 842 effective ~~dates~~January 1, 2019, and elected to adopt using the modified retrospective transition method and practical expedients, both of ~~each acquisition.~~which are provided as options by the standard and further defined below.

Lessee Accounting - At inception, we determine if an arrangement is or contains a lease. Right-of-use assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our payment obligation under the leasing arrangement. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We ~~refer~~use our estimated incremental borrowing rate (“IBR”) to determine the present value of lease payments as most of our leases do not contain an implicit rate. Our IBR represents the interest rate which we would pay to borrow, on a collateralized basis, an amount equal 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~~lease payments over a ~~50% membership interest in Osage~~similar term 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 originatingsimilar economic environment. We use the implicit rate when readily determinable.

Operating leases are recorded 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 Kansasoperating lease right-of-use assets 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.~~

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 connectionscurrent and noncurrent operating lease liabilities on our ~~south products pipeline system~~consolidated balance sheet. Finance leases are included in properties and equipment, current finance lease liabilities and noncurrent finance lease liabilities on our consolidated balance sheet.

When renewal options are defined in a lease, our lease term includes an option to extend the lease when it is reasonably certain we will exercise that ~~will permit HFC access to Magellan’s El Paso terminal. Effective upon the closing~~option. Leases with a term of ~~this exchange, we became the named operator of the Osage Pipeline and transitioned into that role~~12 months or less are not recorded 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~~lease expense is accounted for ~~accounting purposes.~~

~~As we are~~on a ~~consolidated VIE of HFC, this transaction was recorded~~straight-line basis. In addition, as a ~~transfer between entities under common control~~lessee, we separate non-lease components that are identifiable and ~~reflects HFC’s carrying basis in~~exclude them from the determination of net present value of lease payment obligations.

Lessor Accounting - Customer contracts that contain leases are generally classified as either operating leases, direct finance leases or sales-type leases. We consider inputs such as the lease term, fair value of the underlying asset and residual value of the underlying assets ~~acquired.~~when assessing the classification.

Accounting Pronouncements Adopted During the Periods Presented

Credit Losses Measurement

In June 2016, ASU 2016-13, “Measurement of Credit Losses on Financial Instruments,” was issued requiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. We adopted this standard effective January 1, 2020, and adoption of the standard did not have ~~retrospectively adjusted~~a material impact on our financial ~~position and operating~~condition, results ~~as if these units were owned for all periods while we were under common control~~ of ~~HFC.~~operations or cash flows.

~~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 September 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.

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.

The following tables present lines in our previously reported income statement for the three and nine months ended September 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 nine months ended September 30, 2016. However, the presentation of the Tulsa Tanks’ Predecessor transactions have been modified as shown in the table below.

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Three Months Ended September 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)
$ 27,954
$ —
$ 4,147
$ 32,101
        Depreciation and amortization 15,520
—
3,400
18,920
Allocation of net loss attributable to predecessor —
—
7,547
7,547

Nine Months Ended September 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)
$ 82,131
$ —
$ 7,037
$ 89,168
        Depreciation and amortization 47,780
—
3,403
51,183
Allocation of net loss attributable to predecessor —
217
10,440
10,657
Note 2:Investment in Joint Venture

The following tables present lines in our previously reported cash flows for the nine months ended September 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 nine months ended September 30, 2016.

Nine Months Ended September 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 $ 125,111
$ (10,440 ) $ 114,671
Depreciation and amortization 47,780
3,403
51,183
Net cash provided (used) by operating activities $ 185,011
$ (7,037 ) $ 177,974

Cash flows from investing activities
Purchase of Woods Cross refinery processing units $ —
$ (47,891 ) $ (47,891 )
Net cash used for investing activities $ (89,230 ) $ (47,891 ) $ (137,121 )

Cash flows from financing activities
Contributions from HFC for acquisitions $ 99
$ 54,928
$ 55,027
Net cash provided (used) by financing activities $ (103,586 ) $ 54,928
$ (48,658 )

~~SLC Pipeline and Frontier Aspen~~

On October ~~31, 2017, we acquired the remaining 75% interest in SLC Pipeline~~2, 2019, HEP Cushing LLC (“HEP Cushing”), a wholly-owned subsidiary of HEP, and ~~the remaining 50% interest in Frontier Aspen from subsidiaries~~Plains Marketing, L.P. (“PMLP”), a wholly-owned subsidiary of Plains All American Pipeline, L.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for ~~total consideration~~(i) the development and construction of ~~$250 million. As~~a new 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that will connect the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of ~~September 30,~~HFC and (ii) the ownership and operation of 1.5 million barrels of crude oil storage in Cushing, Oklahoma (the “Cushing Connect JV Terminal”). The Cushing Connect JV Terminal went in service during the second quarter of 2020, and the Cushing Connect Pipeline is expected to be placed in service during the third quarter of 2021. Long-term commercial agreements have been entered into to support the Cushing Connect Joint Venture assets.

~~2017, we held noncontrolling interests~~The Cushing Connect Joint Venture contracted with an affiliate of ~~25%~~HEP to manage the construction and operation of ~~SLC~~the Cushing Connect Pipeline and ~~50%~~with an affiliate of ~~Frontier Aspen. As a result~~Plains to manage the operation of the ~~acquisitions, SLC~~Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment will generally be shared equally among the partners. However, we are solely responsible for any Cushing Connect Pipeline construction costs that exceed the budget by more than 10%. HEP estimates its share of the cost of the Cushing Connect JV Terminal contributed by Plains and ~~Frontier Aspen~~Cushing Connect Pipeline construction costs will be approximately $70 million to $75 million.

The Cushing Connect Joint Venture legal entities are ~~wholly-owned subsidiaries~~variable interest entities ("VIEs") as defined under GAAP. A VIE is a legal entity if it has any one of ~~HEP.~~

~~This acquisition will accounted~~the following characteristics: (i) the entity does not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support; (ii) the at risk equity holders, as a ~~business combination achieved~~group, lack the characteristics of a controlling financial interest; or (iii) the entity is structured with non-substantive voting rights. The Cushing Connect Joint Venture legal entities do not have sufficient equity at risk to finance their activities without additional financial support. Since HEP is constructing and will operate the Cushing Connect Pipeline, HEP has more ability to direct the activities that most significantly impact the financial performance of the Cushing Connect Joint Venture and Cushing Connect Pipeline legal entities. Therefore, HEP consolidates those legal entities. We do not have the ability to direct the activities that most significantly impact the Cushing Connect JV Terminal legal entity, and therefore, we account for our interest in ~~stages with~~ the ~~consideration allocated~~Cushing Connect JV Terminal legal entity using the equity method of accounting.

With the exception of the assets of HEP Cushing, creditors of the Cushing Connect Joint Venture legal entities have no recourse to our assets. Any recourse to HEP Cushing would be limited to the ~~acquisition date fair value~~extent of HEP Cushing's assets, which other than its investment in Cushing Connect Joint Venture, are not significant. Furthermore, our creditors have no recourse to the assets of the Cushing Connect Joint Venture legal entities.

Note 3:Revenues

Disaggregated revenues were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)				(In thousands)
Pipelines	$	68,322	$	58,954	$	134,827	$	129,426
Terminals, tanks and loading racks	36,887		36,280		75,069		73,778
Refinery processing units	21,026		19,573		43,522		39,457
	$	126,235	$	114,807	$	253,418	$	242,661

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Revenues on our consolidated statements of income were composed of the following lease and service revenues:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)				(In thousands)
Lease revenues	$	86,867	$	86,346	$	174,803	$	179,493
Service revenues	39,368		28,461		78,615		63,168
	$	126,235	$	114,807	$	253,418	$	242,661

A contract liability exists when an entity is obligated to perform future services for a customer for which the entity has received consideration. Since HEP may be required to perform future services for these deficiency payments received, the deferred revenues on our balance sheets were considered contract liabilities. A contract asset exists when an entity has a right to consideration in exchange for goods or services transferred to a customer. Our consolidated balance sheets included the contract assets and liabilities ~~acquired.~~ in the table below:


	June 30, 2021		December 31, 2020
	(In thousands)
Contract assets	$	6,545	$	6,306
Contract liabilities	$	(400)	$	(500)

The ~~preexisting equity interests~~contract assets and liabilities include both lease and service components. During the six months ended June 30, 2021, we recognized $0.5 million of revenue that was previously included in ~~SLC Pipeline and Frontier Aspen will be remeasured at acquisition date fair value since~~contract liability as of December 31, 2020. During the six months ended June 30, 2021, we ~~will have a controlling interest, and~~also recognized $0.2 million of revenue included in contract assets.

As of June 30, 2021, we expect to recognize ~~a gain on~~$1.8 billion in revenue related to our unfulfilled performance obligations under the ~~remeasurement~~terms of our long-term throughput agreements and leases expiring in 2022 through 2036. These agreements generally provide for changes in the ~~fourth quarter of 2017.~~

~~SLC Pipeline is~~minimum revenue guarantees annually for increases or decreases in the ~~owner of a 95-mile crude pipeline~~Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index, with certain contracts having provisions that ~~transports crude oil into~~limit the ~~Salt Lake City area from the Utah terminal~~level of the ~~Frontier Pipeline~~rate increases or decreases. We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and ~~from Wahsatch Station. Frontier Aspen is the owner~~lease revenues):


Years Ending December 31,	(In millions)
Remainder of 2021	$	168
2022	311
2023	275
2024	237
2025	171
2026	157
Thereafter	484
Total	$	1,803

Payment terms under our contracts with customers are consistent with industry norms and are typically payable within 10 to 30 days of ~~a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.~~

~~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.~~ invoice.

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Note 4:Leases

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 $7.5 million and $10.7 million for the three and nine months ended September 30, 2016. These reductions had no impact on the historical earnings per limited partner unit as they were allocated to the general partner.

~~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 standardASC 842 effective January 1, ~~2017, with no impact~~2019, and elected 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~~

Lessee Accounting

As a ~~cumulative effect adjustment is recorded~~lessee, we lease land, buildings, pipelines, transportation and other equipment to ~~retained earnings~~support our operations. These leases can be categorized into operating and finance leases.

Our leases have remaining terms of less than 1 year to 24 years, some of which include options to extend the leases for up to 10 years.

Finance Lease Obligations

We have finance lease obligations related to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under finance leases was $6.0 million and $6.4 million as of June 30, 2021 and December 31, 2020, respectively, with accumulated depreciation of $3.3 million and $3.4 million as of June 30, 2021 and December 31, 2020, respectively. We include depreciation of finance leases in depreciation and amortization in our consolidated statements of income.

In addition, we have a finance lease obligation related to a pipeline lease with an initial term of 10 years with 1 remaining subsequent renewal option for an additional 10 years.

Supplemental balance sheet information related to leases was as follows (in thousands, except for lease term and discount rate):


	June 30, 2021		December 31, 2020

Operating leases:
Operating lease right-of-use assets, net	$	2,724	$	2,979

Current operating lease liabilities	795		875
Noncurrent operating lease liabilities	2,303		2,476
Total operating lease liabilities	$	3,098	$	3,351

Finance leases:
Properties and equipment	$	6,019	$	6,410
Accumulated amortization	(3,255)		(3,390)
Properties and equipment, net	$	2,764	$	3,020

Current finance lease liabilities	$	3,755	$	3,713
Noncurrent finance lease liabilities	66,434		68,047
Total finance lease liabilities	$	70,189	$	71,760

Weighted average remaining lease term (in years)
Operating leases	5.8		5.9
Finance leases	15.5		15.9

Weighted average discount rate
Operating leases	4.7%		4.8%
Finance leases	5.6%		5.6%

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Supplemental cash flow and other information related to leases were as follows:


	Six Months Ended June 30,
	2021		2020
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows on operating leases	$	576	$	518
Operating cash flows on finance leases	$	2,105	$	2,157
Financing cash flows on finance leases	$	1,747	$	1,972

Maturities of lease liabilities were as follows:


	June 30, 2021
	Operating		Finance
	(In thousands)
2021	$	507	$	3,662
2022	690		7,332
2023	603		7,375
2024	497		6,918
2025	429		6,456
2026 and thereafter	787		73,888
Total lease payments	3,513		105,631
Less: Imputed interest	(415)		(35,442)
Total lease obligations	3,098		70,189
Less: Current lease liabilities	(795)		(3,755)
Noncurrent lease liabilities	$	2,303	$	66,434

The components of lease expense were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)
Operating lease costs	$	249	$	230	$	547	$	503
Finance lease costs
Amortization of assets	200		273		412		515
Interest on lease liabilities	994		1,040		2,001		2,077
Variable lease cost	67		46		133		95
Total net lease cost	$	1,510	$	1,589	$	3,093	$	3,190

Lessor Accounting

As discussed in Note 1, 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~~majority 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~~customers meet the definition of a ~~business~~lease.

Substantially all of the assets supporting contracts meeting the definition of a lease have long useful lives, and we believe these assets will continue to have value when the current agreements expire due to our risk management strategy for protecting the residual fair value of the underlying assets by performing ongoing maintenance during the lease term. HFC generally has the option to purchase assets located within HFC refinery boundaries, including refinery tankage, truck racks and refinery processing units, at fair market value when the related agreements expire.

During the six months ended June 30, 2021, we entered into new agreements and modified other agreements with HFC related to our Cheyenne assets, Tulsa West lube racks, various crude tanks, and new Navajo tanks. These agreements met the criteria of sales-type leases since the underlying assets are not expected to have an alternative use at the end of the lease terms to anyone

- 15 -

other than HFC. Under sales-type lease accounting, at the commencement date, the lessor recognizes a net investment in ~~relation~~the lease, based on the estimated fair value of the underlying leased assets at contract inception, and derecognizes the underlying assets with the difference recorded as selling profit or loss arising from the lease. Therefore, we recognized a gain on sales-type leases during the six months ended June 30, 2021 composed of the following:



	Six Months Ended June 30, 2021
	(In thousands)
Net investment in leases	$	47,795
Properties and equipment, net	(29,677)
Deferred revenue	6,559
Gain on sales-type leases	$	24,677

During the six months ended June 30, 2020, one of our throughput agreements with Delek was partially renewed. A component of this agreement met the criteria of sales-type leases since the underlying asset is not expected to have an alternative use at the end of the lease term to anyone other than Delek. Under sales-type lease accounting, ~~for identifiable intangible~~at the commencement date, the lessor recognizes a net investment in the lease, based on the estimated fair value of the underlying leased assets ~~in business combinations. This standard has an effective~~at the commencement date of ~~January 1, 2018,~~the lease, and derecognizes the underlying assets with the difference recorded as selling profit or loss arising from the lease. Therefore, we recognized a gain on sales-type leases during the six months ended June 30, 2020 composed of the following:


	Six Months Ended June 30, 2020
	(In thousands)
Net investment in lease	$	35,319
Properties and equipment, net	(1,485)

Gain on sales-type lease	$	33,834

These sales-type lease transactions, including the related gain, were non-cash transactions.

Lease income recognized was as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)
Operating lease revenues	$	84,426	$	84,872	$	170,698	$	175,671
Direct financing lease interest income	523		524		1,047		1,048
Gain on sales-type leases	27		33,834		24,677		33,834
Sales-type lease interest income	6,091		2,286		12,115		3,940
Lease revenues relating to variable lease payments not included in measurement of the sales-type lease receivable	2,441		1,474		4,105		3,822

For our sales-type leases, we included customer obligations related to minimum volume requirements in guaranteed minimum lease payments. Portions of our minimum guaranteed pipeline tariffs for assets subject to sales-type lease accounting are ~~evaluating its impact.~~

~~Financial Assets and Liabilities~~

~~In January 2016, an accounting standard update was issued requiring changes in~~recorded as interest income with 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~~remaining amounts recorded as a reduction in net investment in leases. We recognized any billings for throughput volumes in excess of minimum volume requirements as variable lease ~~liability, with a corresponding right-of-use asset~~payments, and these variable lease payments were recorded in lease revenues.

- 16 -

Annual minimum undiscounted lease payments under our leases were as follows as of June 30, 2021:


	Operating		Finance		Sales-type
Years Ending December 31,	(In thousands)
Remainder of 2021	$	141,624	$	1,088	$	14,481
2022	283,151		2,171		28,962
2023	252,705		2,175		25,056
2024	216,601		2,192		21,827
2025	153,746		2,209		18,399
2026 and thereafter	558,415		38,837		144,721
Total lease receipt payments	$	1,606,242	$	48,672	$	253,446
Less: Imputed interest			(32,255)		(198,123)
			16,417		55,323
Unguaranteed residual assets at end of leases			0		144,036
Net investment in leases			$	16,417	$	199,359

Net investments in leases recorded on our balance sheet were composed of the following:


	June 30, 2021				December 31, 2020
	Sales-type Leases		Direct Financing Leases		Sales-type Leases		Direct Financing Leases
	(In thousands)				(In thousands)
Lease receivables (1)	$	126,147	$	16,417	$	88,922	$	16,452
Unguaranteed residual assets	73,212		0		64,551		0
Net investment in leases	$	199,359	$	16,417	$	153,473	$	16,452

(1) Current portion of lease receivables included in prepaid and other current assets on the balance sheet.

Note 5:Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. 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 ~~standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard.~~includes valuation techniques that involve significant unobservable inputs.


~~Note 2:~~	Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, ~~debt~~ and ~~interest rate swaps.~~debt. 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:

- 17 -

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

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

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

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

June 30, 2021

December 31, 2020

Financial Instrument

Fair Value Input Level

Carrying
Value

Fair Value

Carrying
Value

Fair Value

(In thousands)

Liabilities:

5% Senior Notes

Level 2

492,570

512,245

492,103

506,540

September 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 $ —
$ —
$ 91
$ 91

Liabilities:
6.5% Senior notes Level 2 $ —
$ —
$ 297,519
$ 308,250
6% Senior notes Level 2 495,066
524,390
393,393
415,500
$ 495,066
$ 524,390
$ 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. See Note 9 for additional information.

Non-Recurring Fair Value Measurements

For gains on sales-type leases recognized during the six months ended June 30, 2021, the estimated fair value of the underlying leased assets at contract inception and the present value of the estimated unguaranteed residual asset at the end of the lease term are used in determining the net investment in leases and related gain on sales-type leases recorded. The asset valuation estimates include Level 3 inputs based on a replacement cost valuation method.

During the six months ended June 30, 2021, we recognized goodwill impairment based on fair value measurements utilized during our goodwill testing (see Note 1). The fair value ~~of our interest rate swaps is~~measurements were based on ~~the net present value~~a combination of ~~expected future~~valuation methods including discounted cash flows, ~~related to both variable~~the guideline public company and ~~fixed-rate legs~~guideline transaction methods and obsolescence adjusted replacement costs, all of ~~the swap agreement. This measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input.~~which are Level 3 inputs.

~~See~~

Note ~~6 for additional information on these instruments.~~6:Properties and Equipment


~~Note 3:~~	~~Properties and Equipment~~

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


	June 30, 2021		December 31, 2020
	(In thousands)
Pipelines, terminals and tankage1	$	1,538,892	$	1,575,815
Refinery assets	348,882		348,882
Land and right of way	86,781		87,076
Construction in progress	99,420		58,467
Other1	44,819		46,201
	2,118,794		2,116,441
Less accumulated depreciation	(688,483)		(665,756)
	$	1,430,311	$	1,450,685

September 30,
2017 December 31,
2016
(In thousands)
Pipelines, terminals and tankage $ 1,250,567
$ 1,246,746
Refinery assets 347,312
346,058
Land and right of way 65,337
65,331
Construction in progress 51,297
28,753
Other 27,708
27,133
1,742,221
1,714,021
Less accumulated depreciation 435,128
385,626
$ 1,307,093
$ 1,328,395

(1)Prior period balances have been reclassified to be comparative to current period.

We capitalized $0.3 million and $0.2 million during the three months ended September 30, 2017 and 2016, respectively and $0.7 million and $0.5 million during the nine months ended September 30, 2017 and 2016, respectively, in interest attributable to construction projects.

Depreciation expense was ~~$52.1~~$42.7 million and ~~$45.5~~$41.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~,2020, respectively, and includes depreciation of assets acquired under capital leases.


~~Note 4:~~	~~Transportation Agreements~~

~~Our~~Note 7:Intangible Assets

Intangible assets include transportation agreements ~~are intangible assets~~and customer relationships that represent a portion of the total purchase price of certain assets acquired from ~~Alon~~Delek 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),~~HFC, from Plains in 2017, and ~~the HFC agreement is being amortized over 15 years ending 2023 (the term of the HFC agreement).~~from other minor acquisitions in 2018.

- 18 -

The carrying amounts of our ~~transportation agreements are~~intangible assets were as follows:


	Useful Life	June 30, 2021		December 31, 2020
		(In thousands)
Delek transportation agreement	30 years	$	59,933	$	59,933
HFC transportation agreement	10-15 years	75,131		75,131
Customer relationships	10 years	69,683		69,683
Other	20 years	50		50
		204,797		204,797
Less accumulated amortization		(124,486)		(117,482)
		$	80,311	$	87,315

September 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 72,570
67,358
$ 61,644
$ 66,856

Amortization expense was ~~$5.2~~$7.0 million for ~~each of~~both the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016.~~2020. We estimate amortization expense to be $14.0 million for 2022, $9.9 million in 2023, and $9.1 million for 2024 through 2026.

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~~variable interest entity of HFC; therefore, our basis in these agreements is ~~zero~~0 and does not reflect a step-up in basis to fair value.


~~Note 5:~~	~~Employees, Retirement and Incentive Plans~~

Note 8: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.~~HFC (the “Omnibus Agreement”). These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was ~~$1.5~~$1.9 million and ~~$1.4~~$1.6 million for the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively, and ~~$4.5~~$4.1 million and ~~$4.3~~$3.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016.~~2020.

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~~4 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 ~~September~~June 30, ~~2017~~,2021, we had ~~two~~2 types of incentive-based awards outstanding, which are described below. The compensation cost charged against income was ~~$0.7~~$0.5 million for ~~each of~~both the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~,2020, and ~~$1.6~~$1.2 million and ~~$1.9~~$1.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of ~~September~~June 30, ~~2017~~, 2021, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which ~~1,409,261 have not yet been~~856,171 were available to be granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.

~~Restricted~~Phantom Units

Under our Long-Term Incentive Plan, we grant ~~restricted~~phantom units to our 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~~phantom unit award is measured at the market price as of the date of grant and is amortized on a straight-line basis over the requisite service period for each separately vesting portion of the award.

- 19 -

A summary of ~~restricted~~phantom unit activity and changes during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, is presented below:


Phantom Units	Units	Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2021 (nonvested)	295,992	$	14.48

Vesting and transfer of full ownership to recipients	(189)	11.92
Forfeited	(3,483)	14.69
Outstanding at June 30, 2021 (nonvested)	292,320	14.48

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 (20,106 ) 30.10
Outstanding at September 30, 2017 (nonvested) 124,230
$ 33.92

The grant date fair values of phantom units that were vested and transferred to recipients during the six months ended June 30, 2021 and 2020 were $2 thousand and $0.1 million, respectively. As of ~~September~~June 30, ~~2017, there was $1.1~~2021, $2.0 million of total unrecognized compensation expense related to ~~nonvested restricted~~unvested phantom unit grants ~~which~~ is expected to be recognized over a weighted-average period of ~~0.9 year.~~1.3 years.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected ~~executives~~officers who perform services for us. Performance units granted are payable in common units at the end of a three-year performance period based upon meeting certain criteria over the performance period. Under the terms of our performance unit grants, some awards are subject to the growth in our distributable cash flow per common unit over the performance ~~period. As~~period while other awards are subject to "financial performance" and "market performance." Financial performance is based on meeting certain earnings before interest, taxes, depreciation and amortization ("EBITDA") targets, while market performance is based on the relative standing of ~~September 30, 2017, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target~~total unitholder return achieved by HEP compared to peer group companies. The number of ~~performance~~ units ~~granted.~~ultimately issued under these awards can range from 0% to 200%.

We did not grant any performance units during the ~~nine~~six months ended ~~September~~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.~~2021. Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the ~~common~~target number of performance units subject to the award from the date of ~~grant.~~grant at the same rate as distributions paid on our common units.

A summary of performance unit activity and changes ~~during~~for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~,2021, is presented below:



Performance Units	Units
Outstanding at January 1, ~~2017~~2021 (nonvested)	~~49,520~~77,472

Vesting and transfer of common units to recipients	~~(2,262~~(10,881)	)
~~Forfeited~~	~~(21,228~~		)
Outstanding at ~~September~~June 30, ~~2017~~2021 (nonvested)	~~26,030~~66,591

The ~~grant-date~~grant date fair value of performance units vested and transferred to recipients during both of the ~~nine~~six months ended ~~September~~June 30, ~~2017~~,2021 and 2020 was ~~$0.1~~$0.4 million. Based on the ~~weighted average~~weighted-average fair value of performance units outstanding at ~~September~~June 30, ~~2017,~~2021, of ~~$0.9~~$1.2 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~~1.7 years.

During the six months ended June 30, 2021, we did not purchase any of our common units in the open market for the issuance and settlement of unit awards under our Long-Term Incentive Plan.


~~Note 6:~~	~~Debt~~

Note 9:Debt

Credit Agreement

~~We have a $1.4 billion~~In April 2021, we amended our senior secured revolving credit facility (the “Credit Agreement”) ~~expiring in~~decreasing the size of the facility from $1.4 billion to $1.2 billion and extending the maturity date to July ~~2022.~~27, 2025. 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~~continues to provide for an accordion feature ~~giving~~that allows us ~~the ability~~ to increase commitments under the ~~size of the facility by~~Credit Agreement up to ~~$300 million with additional lender commitments.~~a maximum amount of $1.7 billion.

- 20 -

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~~maturity of the Credit Agreement, HEP obtains two investment grade credit ratings, the Credit Agreement will become unsecured and many of the covenants, limitations, and restrictions will be eliminated.

We may prepay all loans ~~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 under the Credit Agreement as of ~~September~~June 30, ~~2017.~~2021.

Senior Notes

On ~~July 19, 2016,~~February 4, 2020, we closed a private placement of ~~$400~~$500 million in aggregate principal amount of 6%5% senior unsecured notes due in ~~2024~~2028 (the ~~“ 6%~~"5% Senior ~~Notes”~~Notes"). On ~~September 22, 2017,~~February 5, 2020, we ~~closed a private placement of an additional $100~~redeemed the existing $500 million ~~in aggregate offering of the~~ 6% Senior Notes ~~for~~at a ~~combined aggregate principal amount outstanding~~redemption cost of ~~$500~~$522.5 million, ~~maturing in 2024.~~at which time we recognized a $25.9 million early extinguishment loss consisting of a $22.5 million debt redemption premium and unamortized financing costs of $3.4 million. We funded the $522.5 million redemption with net proceeds from the issuance of our 5% Senior Notes and borrowings under our Credit Agreement.

The 6%5% 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%5% Senior Notes as of ~~September~~June 30, ~~2017.~~2021. At any time when the 6%5% Senior Notes are rated investment grade by ~~both~~either Moody’s ~~and~~or 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%5% Senior Notes.

Indebtedness under the 6%5% Senior Notes is guaranteed by all of our existing wholly-owned ~~subsidiaries.~~subsidiaries (other than Holly Energy Finance Corp. and certain immaterial subsidiaries).

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.

Long-term Debt

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

September 30,
2017 December 31,
2016
(In thousands)
Credit Agreement
Amount outstanding $ 750,000
$ 553,000

6% Senior Notes
Principal 500,000
400,000
Unamortized premium and debt issuance costs (4,934 ) (6,607 )
495,066
393,393
6.5% Senior Notes
Principal —
300,000
Unamortized discount and debt issuance costs —
(2,481 )
—
297,519

Total long-term debt $ 1,245,066
$ 1,243,912

~~Interest Rate Risk Management~~

~~The two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement advances matured on July 31, 2017, and~~ were ~~not renewed. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.~~

~~Additional information on our interest rate swaps is~~ as follows:


	June 30, 2021		December 31, 2020
	(In thousands)
Credit Agreement
Amount outstanding	$	870,000	913,500






5% Senior Notes
Principal	500,000		500,000
Unamortized premium and debt issuance costs	(7,430)		(7,897)
	492,570		492,103

Total long-term debt	$	1,362,570	$	1,405,603

- 21 -

Derivative Instrument Balance Sheet Location Fair Value Location of Offsetting Balance
Offsetting
Amount
(In thousands)
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:~~

Nine Months Ended September 30,
2017 2016
(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps $ 20,338
$ 13,600
6.5% Senior Notes 163
14,632
6% Senior Notes 18,150
4,811
Amortization of discount and deferred debt issuance costs 2,317
2,294
Commitment fees and other 1,137
1,419
Total interest incurred 42,105
36,756
Less capitalized interest 746
498
Net interest expense $ 41,359
$ 36,258
Cash paid for interest $ 53,181
$ 33,896

~~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 $5.2 million and $4.9 million as of September 30, 2017 and December 31, 2016, respectively, with accumulated

depreciation of $3.2 million and $2.4 million as of September 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 93% 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:~~

Three Months Ended September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
HFC 86 % 84 % 85 % 83 %
Alon 7 % 8 % 7 % 8 %


~~Note 8:~~	~~Related Party Transactions~~

Note 10:Related Party Transactions

We serve HFC’s refineries under long-term pipeline, terminal and tankage throughput agreements, and refinery processing unit tolling agreements expiring from ~~2019~~2022 to ~~2036.~~2036, and revenues from HFC accounted for 79% of our total revenues for both the three and six months ended June 30, 2021. Under these agreements, HFC agrees to transport, store and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminals, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual rate adjustments on July 1st each year generally based on increases or decreases in PPI or the ~~Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”)~~FERC index. As of ~~September~~June 30, ~~2017,~~2021, these agreements with HFC require minimum annualized payments to us of ~~$321.3~~$340 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”),~~the Omnibus Agreement, we pay HFC an annual administrative fee (currently ~~$2.5 million~~)$2.6 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~~were as follows:

•Revenues received from HFC were ~~$95.1~~$99.1 million and ~~$77.4~~$95.6 million for the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~,2020, respectively, and ~~$277.3~~$201.1 million and ~~$239.4~~$197.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively.

•HFC charged us general and administrative services under the Omnibus Agreement of ~~$0.6~~$0.7 million for ~~each of~~both the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, and ~~$1.8~~$1.3 million for ~~each of~~both the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016.~~2020.

•We reimbursed HFC for costs of employees supporting our operations of ~~$11.7~~$14.3 million and ~~$10.0~~$13.2 million for the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively, and ~~$34.5~~$28.7 million and ~~$29.4~~$27.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively.

•HFC reimbursed us ~~$1.9~~$1.2 million and ~~$4.5~~$0.9 million for the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively, and ~~$4.7~~$4.3 million and ~~$11.2~~$4.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively, for expense and capital projects.

•We distributed ~~$32.8~~$20.9 million and ~~$26.2~~$18.4 million ~~for~~ in the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~,2020, respectively, and ~~$94.8~~$41.7 million and ~~$76.0~~$56.0 million ~~for~~in the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively, to HFC as regular distributions on its common ~~units and general partner interest, including general partner incentive distributions.~~

units.

•Accounts receivable from HFC were ~~$42.8~~$46.3 million and ~~$42.6~~$48.0 million at ~~September~~June 30, ~~2017~~,2021, and December 31, ~~2016~~,2020, respectively.

•Accounts payable to HFC were ~~$9.6~~$15.0 million and ~~$16.4~~$18.1 million at ~~September~~June 30, ~~2017~~,2021, and December 31, ~~2016~~,2020, respectively.

~~Revenues for the nine months ended~~ ~~September 30, 2017~~ ~~and~~ ~~2016, include $3.5 million and $5.7 million, respectively, of shortfall payments billed to HFC in 2016 and 2015, respectively.~~ •Deferred revenue in the consolidated balance sheets at ~~September~~included $0.4 million for both June 30, ~~2017~~2021 and December 31, ~~2016, includes $5.8 million and $5.6 million, respectively,~~2020, relating to certain shortfall billings to HFC. ~~It is possible that~~

•We received direct financing lease payments from HFC ~~may not exceed its minimum obligations to receive credit~~ for ~~any~~use of our Artesia and Tulsa rail yards of $0.5 million for both of the ~~$5.8~~three months ended June 30, 2021 and 2020, respectively, and $1.0 million ~~deferred~~for both the six months ended June 30, 2021 and 2020.

•We recorded a gain on sales-type leases with HFC of $24.7 million for the six months ended June 30, 2021, and we received sales-type lease payments of $6.3 million and $2.4 million from HFC that were not recorded in revenues for the three months ended June 30, 2021 and 2020, respectively, and $12.5 million and $4.8 million for the six months ended June 30, 2021 and 2020, respectively.

•HEP and HFC reached an agreement to terminate the existing minimum volume commitments for HEP’s Cheyenne assets and enter into new agreements, which were finalized and executed on February 8, 2021, with the following

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terms, in each case effective January 1, 2021: (1) a ten-year lease with 2 five-year renewal option periods for HFC’s use of certain HEP tank and rack assets in the Cheyenne Refinery to facilitate renewable diesel production with an annual lease payment of approximately $5 million, (2) a five-year contango service fee arrangement that will utilize HEP tank assets inside the Cheyenne Refinery where HFC will pay a base tariff to HEP for available crude oil storage and HFC and HEP will split any profits generated on crude oil contango opportunities and (3) a $10 million one-time cash payment from HFC to HEP for the termination of the existing minimum volume commitment.

On August 2, 2021, in connection with the Sinclair Transactions (described in Note 17 below), HEP and HFC entered into a Letter Agreement (“Letter Agreement”) pursuant to which, among other things, HEP and HFC agreed, upon the consummation of the Sinclair Transactions, to enter into amendments to certain of the agreements by and among HEP and HFC, including the master throughput agreement, to include within the scope of such agreements the assets to be acquired by HEP pursuant to the Contribution Agreement (described in Note 17 below).

In addition, the Letter Agreement provides that if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, HFC enters into a definitive agreement to divest its refinery in Davis County, Utah (the “Woods Cross Refinery”), then HEP would sell certain assets located at, ~~September 30, 2017.~~

or relating to, the Woods Cross Refinery to HFC in exchange for cash consideration equal to $232.5 million plus the certain accounts receivable of HEP in respect of such assets, with such sale to be effective immediately prior to the closing of the sale of the Woods Cross Refinery by HFC. The Letter Agreement also provides that HEP’s right to future revenues from HFC in respect of such Woods Cross Refinery assets will terminate at the closing of such sale.


~~Note 9:~~	~~Partners’ Equity~~

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

As of ~~September~~June 30, ~~2017~~,2021, HFC held ~~22,380,030~~59,630,030 of our common units, constituting a 57% limited partner interest in us, and held the 2%non-economic general partner ~~interest, which together constituted a~~ ~~36%~~ ownership interest in us. Additionally, HFC owned all incentive distribution rights. See Note 1 for a description of the agreement reached with HEP Logistics, our general partner, subsequent to September 30, 2017, impacting its equity interest in HEP.interest.

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 nine months ended September~~As of June 30, ~~2017,~~2021, HEP has issued ~~1,538,452~~2,413,153 units under this program, providing $52.3 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 September 30, 2017, HEP has issued 2,241,907 units under this program, providing $77.1$82.3 million in gross proceeds.

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

Allocations of Net Income

Net income attributable to HEP is allocated 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.

See Note 1 for a description of the financial restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred subsequent to September 30, 2017. After this restructuring, the general partner interest is no longer entitled to any distributions. Therefore, no distributions were declared for the general partner interest related to the three months ended September 30, 2017.

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

Three Months Ended September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(In thousands)
General partner interest in net income $ (419 ) $ 399
$ 919
$ 1,569
General partner incentive distribution —
14,823
34,128
38,432
Net loss attributable to Predecessor —
(7,547 ) —
(10,657 )
Total general partner interest in net income $ (419 ) $ 7,675
$ 35,047
$ 29,344

Cash Distributions

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

On ~~October 26, 2017,~~July 22, 2021, we announced our cash distribution for the ~~third~~second quarter of ~~2017~~2021 of ~~$0.6450~~$0.35 per unit. The distribution is payable on all common units and will be paid ~~November 14, 2017,~~ August 13, 2021, to all unitholders of record on ~~November 6, 2017. However, Holly Logistics will waive $2.5 million in limited partner cash distributions as discussed in Note 1.~~August 2, 2021.

~~The following table presents the allocation of our~~Our regular quarterly cash ~~distributions~~distribution to the ~~general and~~ limited partners will be $37.0 million for the ~~periods in which they apply.~~three months ended June 30, 2021 and was $34.5 million for the three months ended June 30, 2020. For the six months ended June 30, 2021, the regular quarterly distribution to the limited partners will be $74.1 million and was $68.9 million for the six months ended June 30, 2020. Our distributions are declared subsequent to quarter end; therefore, ~~the~~these amounts ~~presented~~ do not reflect distributions paid during the ~~periods presented below.~~respective period.

Three Months Ended September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(In thousands, except per unit data)
General partner interest in distribution $ —
$ 1,065
$ 2,335
$ 2,992
General partner incentive distribution —
14,823
34,128
38,432
Total general partner distribution —
15,888
36,463
41,424
Limited partner distribution 63,012
37,354
143,326
105,657
Total regular quarterly cash distribution $ 63,012
$ 53,242
$ 179,789
$ 147,081
Cash distribution per unit applicable to limited partners $ 0.6450
$ 0.5950
$ 1.8975
$ 1.7550

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:~~	Note 12: Net Income Per Limited Partner Unit

~~Net~~

Basic net income per unit applicable to the limited partners is ~~computed using~~calculated as net income attributable to the ~~two-class method because we have more than one class~~partners divided by the weighted average limited partners’ units outstanding. Diluted net income per unit assumes, when dilutive, the issuance of ~~participating securities. The classes of participating securities as of September 30, 2017, included common~~the net incremental units ~~general partner~~from phantom units and ~~incentive distribution rights (“IDRs”).~~performance units. 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~~Our dilutive securities are immaterial for all periods presented. See Note 1 for a description of the financial restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred subsequent to September 30, 2017. After this restructuring, the general partner interest is no

longer entitled to any distributions. Therefore, no distributions were declared for the general partner interest related to the three months ended September 30, 2017. In addition, HEP issued 37,250,000 of its common units to HEP Logistics on October 31, 2017 in association with this financial restructuring of the general partner interest.

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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~~Net income per limited partner unit is computed as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands, except per unit data)



Net income attributable to the partners	$	55,745	$	76,470	$	120,142	$	101,331
Less: Participating securities’ share in earnings	(190)		0		(411)		0
Net income attributable to common units	55,555		76,470		119,731		101,331
Weighted average limited partners' units outstanding	105,440		105,440		105,440		105,440
Limited partners' per unit interest in earnings - basic and diluted	$	0.53	$	0.73	$	1.14	$	0.96

Note 13:Environmental

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(In thousands)
Net income attributable to the partners $ 42,071
$ 34,785
$ 108,970
$ 116,880
Less: General partner’s distribution declared (including IDRs) —
(15,888 ) (36,463 ) (41,424 )
Limited partner’s distribution declared on common units (63,012 ) (37,354 ) (143,326 ) (105,657 )
Distributions in excess of net income attributable to the partners $ (20,941 ) $ (18,457 ) $ (70,819 ) $ (30,201 )

General Partner (including IDRs) Limited Partners’ Common Units Total
(In thousands, except per unit data)
Three Months Ended September 30, 2017
Net income attributable to the partners:
Distributions declared $ —
$ 63,012
$ 63,012
Distributions in excess of net income attributable to the partners (419 ) (20,522 ) (20,941 )
Net income attributable to the partners $ (419 ) $ 42,490
$ 42,071
Weighted average limited partners' units outstanding 64,319

Limited partners' per unit interest in earnings - basic and diluted $ 0.66

Three Months Ended September 30, 2016
Net income attributable to the partners:
Distributions declared $ 15,888
$ 37,354
$ 53,242
Distributions in excess of net income attributable to the partners (369 ) (18,088 ) (18,457 )
Net income attributable to the partners $ 15,519
$ 19,266
$ 34,785
Weighted average limited partners' units outstanding 59,223

Limited partners' per unit interest in earnings - basic and diluted $ 0.33

General Partner (including IDRs) Limited Partners’ Common Units Total
(In thousands, except per unit data)
Nine Months Ended September 30, 2017
Net income attributable to partnership:
Distributions declared $ 36,463
$ 143,326
$ 179,789
Distributions in excess of net income attributable to partnership (1,416 ) (69,403 ) (70,819 )
Net income attributable to partnership $ 35,047
$ 73,923
$ 108,970
Weighted average limited partners' units outstanding 63,845

Limited partners' per unit interest in earnings - basic and diluted $ 1.16

Nine Months Ended September 30, 2016
Net income attributable to partnership:
Distributions declared $ 41,424
$ 105,657
$ 147,081
Distributions in excess of net income attributable to partnership (604 ) (29,597 ) (30,201 )
Net income attributable to partnership $ 40,820
$ 76,060
$ 116,880
Weighted average limited partners' units outstanding 58,895

Limited partners' per unit interest in earnings - basic and diluted $ 1.29


~~Note 11:~~	~~Environmental~~

We ~~incurred no expenses~~expensed $0.5 million for the three and six months ended June 30, 2021 for environmental remediation obligations, and we expensed $0.5 million and $0.7 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, as well as the three months ended September 30, 2016. For the nine months ended September 30, 2016, we incurred $0.2 million of expense.~~2020, respectively. The accrued environmental liability, net of expected recoveries from indemnifying parties, reflected in our consolidated balance sheets was ~~$6.4~~$4.3 million and ~~$7.1~~$4.5 million at ~~September~~June 30, ~~2017,~~2021 and December 31, ~~2016,~~2020, respectively, of which ~~$4.7~~$2.2 million and ~~$5.4~~$2.5 million, ~~respectively, were~~was classified as other long-term ~~liabilities.~~liabilities at June 30, 2021 and December 31, 2020. 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 September 30, 2017, and December 31, 2016, our~~Our consolidated balance sheets included additional accrued environmental liabilities of ~~$0.8~~$0.4 million and ~~$0.9~~$0.5 million ~~respectively,~~ for HFC indemnified liabilities as of June 30, 2021and December 31, 2020, respectively, and other assets included equal and offsetting balances representing amounts due from HFC related to indemnifications for environmental remediation liabilities.


~~Note 12:~~	~~Contingencies~~

Note 14: Contingencies

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


~~Note 13:~~	~~Operating Segments~~

Note 15: Segment Information

Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in ~~two~~2 reportable 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~~Pipelines and terminals ~~segment has~~have been aggregated as one reportable segment 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~~reportable segment. Identifiable assets are those used by the segment, whereas other assets are principally equity method investments, cash, deposits and other assets that are not associated with a specific reportable ~~operating~~ segment.

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	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended June 30,				Six Months Ended June 30,
	2017			2016			2017			2016				2021		2020		2021		2020
														(In thousands)
Revenues:													Revenues:
Pipelines and terminals - affiliate	$	74,547		$	73,210		$	219,806		$	226,553		Pipelines and terminals - affiliate	$	78,116	$	75,990	$	157,546	$	157,534
Pipelines and terminals - third-party	15,226			15,212			47,826			50,094			Pipelines and terminals - third-party	27,093		19,244		52,350		45,670
Refinery processing units - affiliate	20,591			4,188			57,510			12,870			Refinery processing units - affiliate	21,026		19,573		43,522		39,457
Total segment revenues	$	110,364		$	92,610		$	325,142		$	289,517		Total segment revenues	$	126,235	$	114,807	$	253,418	$	242,661

Segment operating income:													Segment operating income:
Pipelines and terminals	$	44,896		$	48,928		$	140,546		$	155,657
Pipelines and terminals(1)													Pipelines and terminals(1)	$	49,391	$	45,630	$	90,875	$	104,533
Refinery processing units	10,463			(7,339		)	24,283			(6,491		)	Refinery processing units	9,773		9,406		18,008		19,398
Total segment operating income	55,359			41,589			164,829			149,166			Total segment operating income	59,164		55,036		108,883		123,931
Unallocated general and administrative expenses	(3,623		)	(2,664		)	(8,872		)	(8,618		)	Unallocated general and administrative expenses	(2,847)		(2,535)		(5,815)		(5,237)
Interest and financing costs, net	(13,971		)	(14,339		)	(53,278		)	(35,926		)	Interest and financing costs, net	(7,324)		(10,966)		(14,016)		(26,515)
Equity in earnings of unconsolidated affiliates	5,072			3,767			10,965			10,155
Gain on sale of assets and other	155			112			317			104

Loss on early extinguishment of debt													Loss on early extinguishment of debt	0		0		0		(25,915)
Equity in earnings of equity method investments													Equity in earnings of equity method investments	3,423		2,156		5,186		3,870
Gain on sales-type leases													Gain on sales-type leases	27		33,834		24,677		33,834
Gain (loss) on sale of assets and other													Gain (loss) on sale of assets and other	5,415		468		5,917		974
Income before income taxes	$	42,992		$	28,465		$	113,961		$	114,881		Income before income taxes	$	57,858	$	77,993	$	124,832	$	104,942

Capital Expenditures:													Capital Expenditures:
Pipelines and terminals	$	10,151		$	15,557		$	30,437		$	47,200		Pipelines and terminals	$	25,559	$	11,798	$	58,777	$	30,416
Refinery processing units	—			5,173			238			48,915			Refinery processing units	598		0		598		324
Total capital expenditures	$	10,151		$	20,730		$	30,675		$	96,115		Total capital expenditures	$	26,157	$	11,798	$	59,375	$	30,740


	June 30, 2021		December 31, 2020
	(In thousands)
Identifiable assets:
Pipelines and terminals (2)	$	1,743,374	$	1,729,547
Refinery processing units	295,098		305,090
Other	134,350		132,928
Total identifiable assets	$	2,172,822	$	2,167,565

September 30, 2017 December 31, 2016
(in thousands)
Identifiable assets:
Pipelines and terminals $ 1,353,585
$ 1,369,756
Refinery processing units 335,388
342,506
Other 176,869
171,975
Total identifiable assets $ 1,865,842
$ 1,884,237

~~The refinery processing units~~(1) Pipelines and terminals segment operating ~~segment loss~~income includes goodwill impairment charge of $11.0 million for the ~~three and nine~~six months ended ~~September~~June 30, ~~2016, is due to the net loss attributable to Predecessor.~~2021.

(2) Includes goodwill of $223.7 million as of June 30, 2021 and $234.7 million as of December 31, 2020.


~~Note 14:~~	~~Supplemental Guarantor/Non-Guarantor Financial Information~~

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Note 16: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of HEP (“Parent”) under the 6%5% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect 100% owned subsidiaries, other than Holly Energy Finance Corp. and certain immaterial 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.

- 26 -

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.

Condensed Consolidating Balance Sheet


June 30, 2021	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations		Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	871	$	(423)	$	19,113	$	0	$	19,561
Accounts receivable	0		53,348		7,931		(207)		61,072
Prepaid and other current assets	368		8,156		753		0		9,277
Total current assets	1,239		61,081		27,797		(207)		89,910

Properties and equipment, net	0		1,037,480		392,831		0		1,430,311
Operating lease right-of-use assets	0		2,603		121		0		2,724
Net investment in leases	0		211,550		0		0		211,550
Investment in subsidiaries	1,788,648		299,779		0		(2,088,427)		0
Intangible assets, net	0		80,311		0		0		80,311
Goodwill	0		223,650		0		0		223,650
Equity method investments	0		79,448		37,988		0		117,436
Other assets	9,167		7,763		0		0		16,930
Total assets	$	1,799,054	$	2,003,665	$	458,737	$	(2,088,634)	$	2,172,822

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	0	$	28,247	$	12,515	$	(207)	$	40,555
Accrued interest	10,869		0		0		0		10,869
Deferred revenue	0		10,169		400		0		10,569
Accrued property taxes	0		2,391		2,666		0		5,057
Current operating lease liabilities	0		722		73		0		795
Current finance lease liabilities	0		3,755		0		0		3,755
Other current liabilities	137		2,499		307		0		2,943
Total current liabilities	11,006		47,783		15,961		(207)		74,543

Long-term debt	1,362,570		0		0		0		1,362,570
Noncurrent operating lease liabilities	0		2,303		0		0		2,303
Noncurrent finance lease liabilities	0		66,434		0		0		66,434
Other long-term liabilities	260		11,215		438		0		11,913
Deferred revenue	0		32,645		0		0		32,645
Class B unit	0		54,637		0		0		54,637
Equity - partners	425,218		1,788,648		299,779		(2,088,427)		425,218
Equity - noncontrolling interests	0		0		142,559		0		142,559
Total liabilities and equity	$	1,799,054	$	2,003,665	$	458,737	$	(2,088,634)	$	2,172,822

- 27 -

September 30, 2017 Parent
Guarantor
Restricted Subsidiaries
Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 2
$ 6
$ 7,468
$ —
$ 7,476
Accounts receivable —
46,157
4,096
(170 ) 50,083
Prepaid and other current assets 52
1,988
255
—
2,295
Total current assets 54
48,151
11,819
(170 ) 59,854

Properties and equipment, net —
947,094
359,999
—
1,307,093
Investment in subsidiaries

1,608,736
273,874
—
(1,882,610 ) —
Transportation agreements, net —
61,644
—
—
61,644
Goodwill —
256,498
—
—
256,498
Equity method investments —
163,873
—
—
163,873
Other assets 12,329
4,551
—
—
16,880
Total assets $ 1,621,119
$ 1,755,685
$ 371,818
$ (1,882,780 ) $ 1,865,842

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ —
$ 21,770
$ 1,543
$ (170 ) $ 23,143
Accrued interest 5,000
527
—
—
5,527
Deferred revenue —
13,326
1,501
—
14,827
Accrued property taxes —
4,073
3,414
—
7,487
Other current liabilities 52
3,440
—
—
3,492
Total current liabilities 5,052
43,136
6,458
(170 ) 54,476

Long-term debt 1,245,066
—
—
—
1,245,066
Other long-term liabilities 286
14,996
195
—
15,477
Deferred revenue —
46,405
—
—
46,405
Class B unit —
42,412
—
—
42,412
Equity - partners 370,715
1,608,736
273,874
(1,882,610 ) 370,715
Equity - noncontrolling interest —
—
91,291
—
91,291
Total liabilities and equity $ 1,621,119
$ 1,755,685
$ 371,818
$ (1,882,780 ) $ 1,865,842

Condensed Consolidating Balance Sheet


December 31, 2020	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations		Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,627	$	(987)	$	21,350	$	0	$	21,990
Accounts receivable	0		56,522		6,308		(315)		62,515
Prepaid and other current assets	349		8,366		772		0		9,487
Total current assets	1,976		63,901		28,430		(315)		93,992

Properties and equipment, net	0		1,087,184		363,501		0		1,450,685
Operating lease right-of-use assets	0		2,822		157		0		2,979
Net investment in leases	0		166,316		0		0		166,316
Investment in subsidiaries	1,789,808		286,883		0		(2,076,691)		0
Intangible assets, net	0		87,315		0		0		87,315
Goodwill	0		234,684		0		0		234,684
Equity method investments	0		81,089		39,455		0		120,544
Other assets	4,268		6,782		0		0		11,050
Total assets	$	1,796,052	$	2,016,976	$	431,543	$	(2,077,006)	$	2,167,565

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	0	$	30,252	$	16,463	$	(315)	$	46,400
Accrued interest	10,892		0		0		0		10,892
Deferred revenue	0		10,868		500		0		11,368
Accrued property taxes	0		2,915		1,077		0		3,992
Current operating lease liabilities	0		804		71		0		875
Current finance lease liabilities	0		3,713		0		0		3,713
Other current liabilities	5		2,491		9		0		2,505
Total current liabilities	10,897		51,043		18,120		(315)		79,745

Long-term debt	1,405,603		0		0		0		1,405,603
Noncurrent operating lease liabilities	0		2,476		0		0		2,476
Noncurrent finance lease liabilities	0		68,047		0		0		68,047
Other long-term liabilities	260		12,171		474		0		12,905
Deferred revenue	0		40,581		0		0		40,581
Class B unit	0		52,850		0		0		52,850
Equity - partners	379,292		1,789,808		286,883		(2,076,691)		379,292
Equity - noncontrolling interests	0		0		126,066		0		126,066
Total liabilities and equity	$	1,796,052	$	2,016,976	$	431,543	$	(2,077,006)	$	2,167,565

- 28 -

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

Condensed Consolidating Statement of ~~Comprehensive~~ Income


Three Months Ended June 30, 2021	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-restricted Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues:
Affiliates	$	0	$	92,911	$	6,231	$	0	$	99,142
Third parties	0		20,479		6,614		0		27,093
	0		113,390		12,845		0		126,235
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	0		37,742		4,326		0		42,068
Depreciation and amortization	0		20,651		4,352		0		25,003
General and administrative	907		1,940		0		0		2,847

	907		60,333		8,678		0		69,918
Operating income (loss)	(907)		53,057		4,167		0		56,317

Other income (expense):
Equity in earnings of subsidiaries	69,596		3,605		0		(73,201)		0
Equity in earnings of equity method investments	0		2,793		630		0		3,423
Interest expense	(12,944)		(994)		0		0		(13,938)
Interest income	0		6,614		0		0		6,614
Gain on sales-type lease	0		27		0		0		27
Gain on sale of assets and other	0		5,414		1		0		5,415
	56,652		17,459		631		(73,201)		1,541
Income before income taxes	55,745		70,516		4,798		(73,201)		57,858
State income tax expense	0		(27)		0		0		(27)
Net income	55,745		70,489		4,798		(73,201)		57,831
Allocation of net income attributable to noncontrolling interests	0		(894)		(1,192)		0		(2,086)

Net income attributable to the partners	$	55,745	$	69,595	$	3,606	$	(73,201)	$	55,745

- 29 -

Three Months Ended September 30, 2017 Parent
Guarantor Restricted
Subsidiaries
Non-Guarantor Non-restricted Subsidiaries Eliminations Consolidated
(In thousands)
Revenues:
Affiliates $ —
$ 89,772
$ 5,366
$ —
$ 95,138
Third parties —
10,758
4,468
—
15,226
—
100,530
9,834
—
110,364
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) —
31,360
4,638
—
35,998
Depreciation and amortization

14,854
4,153
—
19,007
General and administrative 1,050
2,573
—
—
3,623
1,050
48,787
8,791
—
58,628
Operating income (loss) (1,050 ) 51,743
1,043
—
51,736

Other income (expense):
Equity in earnings of subsidiaries 57,193
783
—
(57,976 ) —
Equity in earnings of equity method investments —
5,072
—
—
5,072
Interest expense (14,072 ) —
—
—
(14,072 )
Interest income —
101
—
—
101
Gain on sale of assets and other —
154
1
—
155
43,121
6,110
1
(57,976 ) (8,744 )
Income (loss) before income taxes 42,071
57,853
1,044
(57,976 ) 42,992
State income tax benefit —
69
—
—
69
Net income 42,071
57,922
1,044
(57,976 ) 43,061
Allocation of net income attributable to noncontrolling interests —
(729 ) (261 ) —
(990 )
Net income attributable to Holly Energy Partners 42,071
57,193
783
(57,976 ) 42,071
Other comprehensive income (63 ) (63 ) —
63
(63 )
Comprehensive income attributable to Holly Energy Partners $ 42,008
$ 57,130
$ 783
$ (57,913 ) $ 42,008

~~Condensed Consolidating Statement of Comprehensive Income~~

Three Months Ended September 30, 2016 ⁽¹⁾
Parent
Guarantor
Restricted Subsidiaries
Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
(In thousands)
Revenues:
Affiliates $ —
$ 72,389
$ 5,009
$ —
$ 77,398
Third parties —
11,360
3,852
—
15,212
—
83,749
8,861
—
92,610
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) —
29,023
3,078
—
32,101
Depreciation and amortization —
15,093
3,827
—
18,920
General and administrative 813
1,851
—
—
2,664
813
45,967
6,905
—
53,685
Operating income (loss) (813 ) 37,782
1,956
—
38,925

Other income (expense):
Equity in earnings of subsidiaries 44,359
1,451
—
(45,810 ) —
Equity in earnings of equity method investments —
3,767
—
—
3,767
Interest expense (10,011 ) (4,436 ) —
—
(14,447 )
Interest income —
103
5
—
108
Gain (loss) on sale of assets and other —
138
(26 ) —
112
34,348
1,023
(21 ) (45,810 ) (10,460 )
Income before income taxes 33,535
38,805
1,935
(45,810 ) 28,465
State income tax expense —
(61 ) —
—
(61 )
Net income 33,535
38,744
1,935
(45,810 ) 28,404
Allocation of net loss to Predecessor —
7,547
—
—
7,547
Allocation of net income attributable to noncontrolling interests —
(682 ) (484 ) —
(1,166 )
Net income attributable to Holly Energy Partners 33,535
45,609
1,451
(45,810 ) 34,785
Other comprehensive (loss) 296
296
—
(296 ) 296
Comprehensive income attributable to Holly Energy Partners $ 33,831
$ 45,905
$ 1,451
$ (46,106 ) $ 35,081

~~(1) Retrospectively adjusted as described in Note 1.~~

Condensed Consolidating Statement of ~~Comprehensive~~ Income


Three Months Ended June 30, 2020	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues:
Affiliates	$	0	$	89,417	$	6,146	$	0	$	95,563
Third parties	0		15,887		3,357		0		19,244
	0		105,304		9,503		0		114,807
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	0		30,980		3,757		0		34,737
Depreciation and amortization	0		20,739		4,295		0		25,034
General and administrative	780		1,755		0		0		2,535
	780		53,474		8,052		0		62,306
Operating income (loss)	(780)		51,830		1,451		0		52,501

Other income (expense):
Equity in earnings of subsidiaries	89,893		1,510		0		(91,403)		0
Equity in earnings of equity method investments	0		1,449		707		0		2,156
Interest expense	(12,740)		(1,039)		0		0		(13,779)
Interest income	26		2,787		0		0		2,813

Gain on sales-type lease	0		33,834		0		0		33,834
Gain on sale of assets and other	71		396		1		0		468
	77,250		38,937		708		(91,403)		25,492
Income before income taxes	76,470		90,767		2,159		(91,403)		77,993
State income tax expense	0		(39)		0		0		(39)
Net income	76,470		90,728		2,159		(91,403)		77,954
Allocation of net income attributable to noncontrolling interests	0		(835)		(649)		0		(1,484)


Net income attributable to the partners	$	76,470	$	89,893	$	1,510	$	(91,403)	$	76,470

- 30 -

Nine Months Ended September 30, 2017 Parent
Guarantor Restricted
Subsidiaries
Non-Guarantor Non-restricted Subsidiaries Eliminations Consolidated
(In thousands)
Revenues:
Affiliates $ —
$ 258,571
$ 18,745
$ —
$ 277,316
Third parties —
32,146
15,680
—
47,826
—
290,717
34,425
—
325,142
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) —
91,323
11,261
—
102,584
Depreciation and amortization —
45,498
12,231
—
57,729
General and administrative 3,070
5,802
—
—
8,872
3,070
142,623
23,492
—
169,185
Operating income (loss) (3,070 ) 148,094
10,933
—
155,957

Other income (expense):
Equity in earnings (loss) of subsidiaries 165,624
8,203
—
(173,827 ) —
Equity in earnings of equity method investments —
10,965
—
—
10,965
Interest expense (41,359 ) —
—
—
(41,359 )
Interest income —
306
—
—
306
Loss on early extinguishment of debt (12,225 ) —
—
—
(12,225 )
Gain (loss) on sale of assets and other —
313
4
—
317
112,040
19,787
4
(173,827 ) (41,996 )
Income (loss) before income taxes 108,970
167,881
10,937
(173,827 ) 113,961
State income tax expense —
(164 ) —
—
(164 )
Net income (loss) 108,970
167,717
10,937
(173,827 ) 113,797
Allocation of net income attributable to noncontrolling interests —
(2,093 ) (2,734 ) —
(4,827 )
Net income (loss) attributable to Holly Energy Partners 108,970
165,624
8,203
(173,827 ) 108,970
Other comprehensive income (loss) (91 ) (91 ) —
91
(91 )
Comprehensive income (loss) $ 108,879
$ 165,533
$ 8,203
$ (173,736 ) $ 108,879

Condensed Consolidating Statement of ~~Comprehensive~~ Income


Six Months Ended June 30, 2021	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-restricted Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues:
Affiliates	$	0	$	188,612	$	12,456	$	0	$	201,068
Third parties	0		39,530		12,820		0		52,350
	0		228,142		25,276		0		253,418
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	0		75,541		7,892		0		83,433
Depreciation and amortization	0		41,487		8,581		0		50,068
General and administrative	2,085		3,730		0		0		5,815
Goodwill impairment	0		11,034		0		0		11,034
	2,085		131,792		16,473		0		150,350
Operating income (loss)	(2,085)		96,350		8,803		0		103,068

Other income (expense):
Equity in earnings of subsidiaries	147,405		7,741		0		(155,146)		0
Equity in earnings of equity method investments	0		3,411		1,775		0		5,186
Interest expense	(25,178)		(2,000)		0		0		(27,178)
Interest income	0		13,162		0		0		13,162

Gain on sales-type lease	0		24,677		0		0		24,677
Gain on sale of assets and other	0		5,915		2		0		5,917
	122,227		52,906		1,777		(155,146)		21,764
Income before income taxes	120,142		149,256		10,580		(155,146)		124,832
State income tax expense	0		(64)		0		0		(64)
Net income	120,142		149,192		10,580		(155,146)		124,768
Allocation of net income attributable to noncontrolling interests	0		(1,787)		(2,839)		0		(4,626)


Net income attributable to the partners	$	120,142	$	147,405	$	7,741	$	(155,146)	$	120,142

- 31 -

Nine Months Ended September 30, 2016 ⁽¹⁾
Parent
Guarantor
Restricted Subsidiaries
Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
(In thousands)
Revenues:
Affiliates $ —
$ 219,428
$ 19,995
$ —
$ 239,423
Third parties —
33,783
16,311
—
50,094
—
253,211
36,306
—
289,517
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) —
80,248
8,920
—
89,168
Depreciation and amortization —
39,811
11,372
—
51,183
General and administrative 2,949
5,669
—
—
8,618
2,949
125,728
20,292
—
148,969
Operating income (loss) (2,949 ) 127,483
16,014
—
140,548

Other income (expense):
Equity in earnings (loss) of subsidiaries 138,513
12,004
—
(150,517 ) —
Equity in earnings of equity method investments —
10,155
—
—
10,155
Interest expense (20,151 ) (16,107 ) —
—
(36,258 )
Interest income —
315
17
—
332
Gain (loss) on sale of assets and other —
129
(25 ) —
104
118,362
6,496
(8 ) (150,517 ) (25,667 )
Income (loss) before income taxes 115,413
133,979
16,006
(150,517 ) 114,881
State income tax expense —
(210 ) —
—
(210 )
Net income (loss) 115,413
133,769
16,006
(150,517 ) 114,671
Allocation of net loss to Predecessor

10,657
—
—
10,657
Allocation of net income attributable to noncontrolling interests —
(4,446 ) (4,002 ) —
(8,448 )
Net income (loss) attributable to Holly Energy Partners 115,413
139,980
12,004
(150,517 ) 116,880
Other comprehensive income (loss) (299 ) (299 ) —
299
(299 )
Comprehensive income (loss) $ 115,114
$ 139,681
$ 12,004
$ (150,218 ) $ 116,581

~~(1) Retrospectively adjusted as described in Note 1.~~

Condensed Consolidating Statement of ~~Cash Flows~~Income


Six Months Ended June 30, 2020	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-restricted Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues:
Affiliates	$	0	$	184,172	$	12,819	$	0	$	196,991
Third parties	0		35,042		10,628		0		45,670
	0		219,214		23,447		0		242,661
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	0		62,111		7,607		0		69,718
Depreciation and amortization	—		40,492		8,520		0		49,012
General and administrative	1,879		3,358		0		0		5,237
	1,879		105,961		16,127		0		123,967
Operating income (loss)	(1,879)		113,253		7,320		0		118,694

Other income (expense):
Equity in earnings of subsidiaries	158,428		5,805		0		(164,233)		0
Equity in earnings of equity method investments	0		3,537		333		0		3,870
Interest expense	(29,470)		(2,076)		0		0		(31,546)
Interest income	26		5,005		0		0		5,031
Loss on early extinguishment of debt	(25,915)		0		0		0		(25,915)
Gain on sales-type lease	0		33,834		0		0		33,834
Gain on sale of assets and other	141		816		17		0		974
	103,210		46,921		350		(164,233)		(13,752)
Income before income taxes	101,331		160,174		7,670		(164,233)		104,942
State income tax expense	0		(76)		0		0		(76)
Net income	101,331		160,098		7,670		(164,233)		104,866
Allocation of net income attributable to noncontrolling interests	0		(1,670)		(1,865)		0		(3,535)

Net income attributable to the partners	$	101,331	$	158,428	$	5,805	$	(164,233)	$	101,331

- 32 -

Nine Months Ended September 30, 2017 Parent
Guarantor
Restricted Subsidiaries
Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
(In thousands)
Cash flows from operating activities $ (57,045 ) $ 215,643
$ 27,064
$ (8,203 ) $ 177,459

Cash flows from investing activities
Additions to properties and equipment —
(27,725 ) (2,950 ) —
(30,675 )
Distributions from UNEV in excess of earnings —
6,797
—
(6,797 ) —
Proceeds from sale of assets —
794
—
—
794
Distributions in excess of equity in earnings of equity investments —
1,224
—
—
1,224
—
(18,910 ) (2,950 ) (6,797 ) (28,657 )

Cash flows from financing activities
Net borrowings under credit agreement 750,000
(553,000 ) —
—
197,000
Net intercompany financing activities (357,196 ) 357,196
—
—
—
Proceeds from issuance of 6% Senior Notes 103,250
(1,500 ) —
—
101,750
Proceeds from issuance of common units 52,285
—
—
—
52,285
Contribution from general partner 1,072
—
—
—
1,072
Redemption of senior notes (309,750 ) —
—
—
(309,750 )
Distributions to HEP unitholders (171,560 ) —
—
—
(171,560 )
Distribution to HFC for El Dorado tanks (103 ) —
—
—
(103 )
Distributions to noncontrolling interests —
—
(20,000 ) 15,000
(5,000 )
Deferred financing cost (10,953 ) 1,500
—
—
(9,453 )
Other —
(1,224 ) —
—
(1,224 )
57,045
(197,028 ) (20,000 ) 15,000
(144,983 )

Cash and cash equivalents
Increase (decrease) for the period —
(295 ) 4,114
—
3,819
Beginning of period 2
301
3,354
—
3,657
End of period $ 2
$ 6
$ 7,468
$ —
$ 7,476

Note 17: Subsequent Event

~~Condensed Consolidating Statement~~

HEP Transactions

On August 2, 2021, HEP, The Sinclair Companies (“Sinclair”), and Sinclair Transportation Company, a wholly owned subsidiary of ~~Cash Flows~~Sinclair (“STC”), entered into a Contribution Agreement (the “Contribution Agreement”) pursuant to which HEP will acquire all of the outstanding shares of STC in exchange for 21 million newly issued common units of HEP and cash consideration equal to $325 million (the “HEP Transactions”). On the same date, HFC, Sinclair and certain other parties entered into a Business Combination Agreement pursuant to which Sinclair will contribute all of the equity interests of Hippo Holding LLC, which owns Sinclair Oil Corporation, to a new HFC parent holding company that will be named “HF Sinclair Corporation” in exchange for 60,230,036 shares of common stock in HF Sinclair Corporation (the “HFC Transactions”, and together with the HEP Transactions, the “Sinclair Transactions”).

The cash consideration for the HEP Transactions is subject to customary adjustments at closing for working capital of STC. The number of HEP common units to be issued to Sinclair at closing is subject to downward adjustment if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, HEP agrees to divest a portion of its equity interest in UNEV Pipeline LLC and the sales price for such interests does not exceed the threshold provided in the Contribution Agreement.

The Contribution Agreement contains customary representations, warranties and covenants of HEP, Sinclair, and STC. The HEP Transactions are expected to close in mid-2022, subject to the satisfaction or waiver of certain customary conditions, including, among others, the receipt of certain required regulatory consents and clearance, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, and the consummation of the HFC Transactions.

The Contribution Agreement automatically terminates if the HFC Transactions are terminated, and contains other customary termination rights, including a termination right for each of HEP and Sinclair if, under certain circumstances, the closing does not occur by May 2, 2022 (the “Outside Date”), except that the Outside Date can be extended by either party by up to 2 90 day periods to obtain any required antitrust clearance.

Upon closing of the HEP Transactions, HEP’s existing senior management team will continue to operate HEP. Under the definitive agreements, Sinclair will be granted the right to nominate 1 director to the HEP board of directors at the closing. The Sinclair stockholders have also agreed to certain customary lock-up restrictions and registration rights for the HEP common units to be issued to the stockholders of Sinclair. HEP will continue to operate under the name Holly Energy Partners, L.P.

See Note 10 for a description of the Letter Agreement between HFC and HEP entered into in connection with the Contribution Agreement.

- 33 -

Nine Months Ended September 30, 2016 ⁽¹⁾
Parent
Guarantor
Restricted Subsidiaries
Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
(In thousands)
Cash flows from operating activities $ (20,467 ) $ 181,967
$ 27,724
$ (11,250 ) �� $ 177,974

Cash flows from investing activities
Additions to properties and equipment —
(33,147 ) (15,077 ) —
(48,224 )
Purchase of Woods Cross refinery processing units —
(47,891 ) —
—
(47,891 )
Purchase of Cheyenne Pipeline —
(42,550 ) —
—
(42,550 )
Proceeds from sale of assets —
210
—
—
210
Distributions in excess of equity in earnings of equity investments —
1,685
—
—
1,685
Other —
(351 ) —
—
(351 )
—
(122,044 ) (15,077 ) —
(137,121 )

Cash flows from financing activities
Net repayments under credit agreement —
(332,000 ) —
—
(332,000 )
Net intercompany financing activities (257,172 ) 257,172
—
—
—
Proceeds from issuance of senior notes 394,000
—
—
—
394,000
Proceeds from issuance of common units 22,591
200
—
—
22,791
Distributions to HEP unitholders (138,798 ) —
—
—
(138,798 )
Distributions to noncontrolling interests —
—
(15,000 ) 11,250
(3,750 )
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
54,928
—
—
55,027
Contributions from general partner 470
—
—
—
470
Purchase of units for incentive grants (784 ) —
—
—
(784 )
Deferred financing costs (846 ) (3,084 ) —
—
(3,930 )
Other —
(939 ) —
—
(939 )
20,467
(65,375 ) (15,000 ) 11,250
(48,658 )

Cash and cash equivalents
Decrease for the period —
(5,452 ) (2,353 ) —
(7,805 )
Beginning of period 2
5,452
9,559
—
15,013
End of period $ 2
$ —
$ 7,206
$ —
$ 7,208

~~(1) Retrospectively adjusted as described in Note 1.~~

Table of ~~Contentsril 19,~~


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

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.~~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. WeThrough our subsidiaries and joint ventures, we own ~~and~~and/or operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support the refining and marketing operations of HollyFrontier Corporation (“HFC”) and other refineries in the Mid-Continent, Southwest and Northwest regions of the United ~~States and Alon USA, Inc’s (“Alon”) refinery in Big Spring, Texas.~~States. 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~~57% of our outstanding common units and the 2%non-economic general partnership interest as of ~~September~~June 30, ~~2017.~~2021.

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

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

~~Acquisitions~~

On ~~February 22, 2016, HFC obtained a 50% membership interest in Osage Pipe Line~~August 2, 2021, HEP, The Sinclair Companies (“Sinclair”), and Sinclair Transportation 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.

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 also 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 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 September 30, 2017, these commitments provide minimum annualized revenues of $5.7 million.

~~Table of Contentsril 19,~~

~~Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”),~~ a wholly owned subsidiary of ~~HFC,~~Sinclair (“STC”), entered into a Contribution Agreement (the “Contribution Agreement”) pursuant to which ~~owns~~ the HEP will acquire all of the outstanding shares of STC in exchange for 21 million newly ~~constructed atmospheric distillation tower, fluid catalytic cracking unit,~~issued common units of HEP and ~~polymerization unit located at HFC’s Woods Cross Refinery, for~~ cash consideration equal to $325 million (the “HEP Transactions”), subject to downward adjustment if, as a condition to obtaining antitrust clearance for the Sinclair Transactions (as defined below), HEP agrees to divest a portion of ~~$278.0 million.~~its equity interest in UNEV Pipeline LLC and the sales price for such interests does not exceed the threshold provided in the Contribution Agreement.

The Sinclair Transactions are expected to close in mid-2022, subject to customary closing conditions and regulatory clearance, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. In ~~connection~~addition, the HEP Transactions are conditioned on the closing of the transactions contemplated by that certain Business Combination Agreement, dated as of August 2, 2021, by and among HollyFrontier, Sinclair and certain other parties, which will occur immediately following the HEP Transactions (the “HFC Transactions,” and together with ~~this transaction,~~the HEP Transactions, the “Sinclair Transactions”). See Note 17 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.

Impact of COVID-19 on Our Business

Our business depends in large part on the demand for the various petroleum products we ~~entered into 15-year tolling agreements containing~~transport, terminal and store in the markets we serve. The impact of the COVID-19 pandemic on the global macroeconomy created diminished demand, as well as lack of forward visibility, for refined products and crude oil transportation, and for the terminalling and storage services that we provide. Since the declines in demand at the beginning of the COVID-19 pandemic, we began to see improvement in demand for these products and services beginning late in the second quarter of 2020 that continued through the second quarter of 2021 with volumes in many of our regions returning to pre-pandemic levels. We expect our customers will continue to adjust refinery production levels commensurate with market demand, and with the increasing availability of vaccines, we believe there is a path to a fulsome recovery in demand in 2021.

With the increasing vaccination rates, most of our employees have returned to work at our locations and we continue to follow Centers for Disease Control and local government guidance. We will continue to monitor developments in the COVID-19 pandemic and the dynamic environment it has created to properly address these policies going forward.

- 34 -

Table of

In light of current circumstances and our expectations for the future, HEP reduced its quarterly distribution to $0.35 per unit beginning with the distribution for the first quarter of 2020, representative of a new distribution strategy focused on funding all capital expenditures and distributions within operating cash flow and improving distributable cash flow coverage to 1.3x or greater with the goal of reducing leverage to 3.0-3.5x.

The extent to which HEP’s future results are affected by the COVID-19 pandemic will depend on various factors and consequences beyond our control, such as the duration and scope of the pandemic, the effects of any new variant strains of the underlying virus, additional actions by businesses and governments in response to the pandemic and the speed and effectiveness of responses to combat the virus. However, we have long-term customer contracts with minimum ~~quarterly throughput~~volume commitments, which have expiration dates from ~~HFC. As~~2022 to 2036. These minimum volume commitments accounted for approximately 66% and 76% of ~~September~~our total revenues in the six months ended June 30, ~~2017, these commitments provide minimum annualized revenues of $57.3 million.~~

2021 and the twelve months ended December 31, 2020, respectively. We are ~~a consolidated variable interest entity (“VIE”)~~currently not aware of ~~HFC. Therefore,~~any reasons that would prevent such customers from making the ~~acquisitions~~minimum payments required under the contracts or potentially making payments in excess of the ~~crude tanks at HFC's Tulsa refinery on March 31, 2016, and Woods Cross Operating on October 1, 2016, were accounted~~minimum payments. In addition to these payments, we also expect to collect payments for ~~as transfers between entities under common control. Accordingly, this financial data has~~services provided to uncommitted shippers. There have been ~~retrospectively adjusted~~no material changes to ~~include the historical results of these acquisitions for all periods presented prior~~customer payment terms due to the ~~effective dates of each acquisition. We refer~~COVID-19 pandemic.

The COVID-19 pandemic, and the volatile regional and global economic conditions stemming from it, could also exacerbate the risk factors identified in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. The COVID-19 pandemic may also materially adversely affect our results in a manner that is either not currently known or that we do not currently consider to ~~these historical results as those of~~be a significant risk to our ~~"Predecessor." See Note 1 for further discussion of these acquisitions and basis of presentation.~~business.

Investment in Joint Venture

On October ~~31, 2017, we acquired~~2, 2019, HEP Cushing LLC (“HEP Cushing”), a wholly-owned subsidiary of HEP, and Plains Marketing, L.P., a wholly-owned subsidiary of Plains, formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for (i) the ~~remaining 75% interest~~development, construction, ownership and operation of a new 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that will connect the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HFC and (ii) the ownership and operation of 1.5 million barrels of crude oil storage in ~~SLC~~Cushing, Oklahoma (the “Cushing Connect JV Terminal”). The Cushing Connect JV Terminal went in service during the second quarter of 2020, and the Cushing Connect Pipeline is expected to be placed in service during the third quarter of 2021. Long-term commercial agreements have been entered into to support the Cushing Connect Joint Venture assets.

The Cushing Connect Joint Venture has contracted with an affiliate of HEP to manage the construction and operation of the Cushing Connect Pipeline and ~~the remaining 50% interest in Frontier Aspen from subsidiaries~~with an affiliate of Plains All American Pipeline, L.P. (“Plains”), for total consideration of $250 million. As of September 30, 2017, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a resultto manage the operation of the ~~acquisitions, SLC~~Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment will generally be shared equally among HEP and Plains. However, we are solely responsible for any Cushing Connect Pipeline ~~and Frontier Aspen are wholly-owned subsidiaries of HEP.~~

~~This acquisition will accounted for as a business combination achieved in stages with~~construction costs that exceed the consideration allocated to the acquisition date fair value of assets and liabilities acquired. The preexisting equity interests in SLC Pipeline and Frontier Aspen will be remeasured at acquisition date fair value since we will have a controlling interest, and we expect to recognize a gain on the remeasurement in the fourth quarter of 2017.

~~SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal~~budget by more than 10%. HEP estimates its share of the ~~Frontier~~cost of the Cushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline ~~and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming~~construction costs are approximately $70 million to ~~Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.~~$75 million.

Agreements with HFC ~~and Alon~~

We serve ~~HFC’s~~HFC's refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from ~~2019~~2022 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 PPI or the FERC index. On December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index ~~(“PPI”) or Federal Energy Regulatory Commission (“FERC”) index.~~plus 0.78%. FERC has received requests for rehearing of its December 17, 2020 order, which remain pending in FERC Docket No. RM20-14-000. As of ~~September~~June 30, ~~2017,~~2021, these agreements with HFC require minimum annualized payments to us of ~~$321.3~~$340 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 ~~September 30, 2017, these agreements with Alon require minimum annualized payments to us of $33.1 million.~~

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

On June 1, 2020, HFC announced plans to permanently cease petroleum refining operations at its Cheyenne Refinery and to convert certain assets at that refinery to renewable diesel production. HFC subsequently began winding down petroleum refining operations at its Cheyenne Refinery on August 3, 2020.

- 35 -

Table of

On February 8, 2021, HEP and HFC finalized and executed new agreements for HEP's Cheyenne assets with the following terms, in each case effective January 1, 2021: (1) a ten-year lease with two five-year renewal option periods for HFC’s use of certain HEP tank and rack assets in the Cheyenne Refinery to facilitate renewable diesel production with an annual lease payment of approximately $5 million, (2) a five-year contango service fee arrangement that will utilize HEP tank assets inside the Cheyenne Refinery where HFC will pay a base tariff to HEP for available crude oil storage and HFC and HEP will split any profits generated on crude oil contango opportunities and (3) a $10 million one-time cash payment from HFC to HEP for the termination of the existing minimum volume commitment.

Indicators of goodwill and long-lived asset impairment

During the three months ended March 31, 2021, changes in our agreements with HFC related to our Cheyenne assets resulted in an increase in the net book value of our Cheyenne reporting unit due to sales-type lease accounting, which led us to determine indicators of potential goodwill impairment for our Cheyenne reporting unit were present.

The estimated fair values of our Cheyenne reporting unit were derived using a combination of income and market approaches. The income approach reflects expected future cash flows based on anticipated gross margins, operating costs, and capital expenditures. The market approaches include both the guideline public company and guideline transaction methods. Both methods utilize pricing multiples derived from historical market transactions of other like-kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs). See Note 5 for further discussion of Level 3 inputs.

Our interim impairment testing of our Cheyenne reporting unit goodwill identified an impairment charge of $11.0 million, which was recorded in the three months ended March 31, 2021.

Under certain provisions of an omnibus agreement we have with HFC ~~(“Omnibus~~(the “Omnibus Agreement”), we pay HFC an annual administrative fee, currently ~~$2.5~~$2.6 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.

~~Table of Contentsril 19,~~

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.~~HFC that has historically facilitated our growth. Our ~~current~~future growth ~~plan is~~plans include organic projects around our existing assets and select investments or acquisitions that enhance our service platform while creating accretion for our unitholders. While in the near term, any acquisitions would be subject to ~~continue~~economic conditions discussed in “Overview - Impact of COVID-19 on Our Business” above, we also expect over the longer term 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~~continue to work with HFC on logistic asset acquisitions in conjunction with HFC’s refinery acquisition strategies. See “Overview” above for a discussion of the Sinclair Transactions.

Furthermore, as we are doing with the previously discussed HEP Transactions with Sinclair, we plan to continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.

- 36 -

Table of ~~Contentsril 19,~~

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow, Volumes and ~~Volumes~~Balance Sheet Data

The following tables present income, distributable cash flow and volume information for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016. These results have been adjusted~~2020.

- 37 -

Table of


	Three Months Ended June 30,				Change from
	2021		2020		2020
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	19,213	$	16,302	$	2,911
Affiliates—intermediate pipelines	7,521		7,475		46
Affiliates—crude pipelines	19,251		19,311		(60)
	45,985		43,088		2,897
Third parties—refined product pipelines	9,526		8,750		776
Third parties—crude pipelines	12,811		7,116		5,695
	68,322		58,954		9,368
Terminals, tanks and loading racks:
Affiliates	32,131		32,902		(771)
Third parties	4,756		3,378		1,378
	36,887		36,280		607

Refinery processing units—Affiliates	21,026		19,573		1,453

Total revenues	126,235		114,807		11,428
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	42,068		34,737		7,331
Depreciation and amortization	25,003		25,034		(31)
General and administrative	2,847		2,535		312

	69,918		62,306		7,612
Operating income	56,317		52,501		3,816
Other income (expense):
Equity in earnings of equity method investments	3,423		2,156		1,267
Interest expense, including amortization	(13,938)		(13,779)		(159)
Interest income	6,614		2,813		3,801

Gain on sales-type leases	27		33,834		(33,807)
Gain on sale of assets and other	5,415		468		4,947
	1,541		25,492		(23,951)
Income before income taxes	57,858		77,993		(20,135)
State income tax expense	(27)		(39)		12
Net income	57,831		77,954		(20,123)

Allocation of net income attributable to noncontrolling interests	(2,086)		(1,484)		(602)
Net income attributable to the partners	55,745		76,470		(20,725)


Limited partners’ earnings per unit—basic and diluted	$	0.53	$	0.73	$	(0.20)
Weighted average limited partners’ units outstanding	105,440		105,440		—
EBITDA (1)	$	88,099	$	112,509	$	(24,410)
Adjusted EBITDA (1)	$	88,261	$	80,168	$	8,093
Distributable cash flow (2)	$	66,680	$	65,456	$	1,224

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	119,046		100,524		18,522
Affiliates—intermediate pipelines	143,762		128,464		15,298
Affiliates—crude pipelines	260,756		252,570		8,186
	523,564		481,558		42,006
Third parties—refined product pipelines	52,126		57,876		(5,750)
Third parties—crude pipelines	135,904		85,851		50,053
	711,594		625,285		86,309
Terminals and loading racks:
Affiliates	413,441		372,093		41,348
Third parties	53,257		45,876		7,381
	466,698		417,969		48,729
Refinery processing units—Affiliates	76,589		49,891		26,698
Total for pipelines and terminal and refinery processing unit assets (bpd)	1,254,881		1,093,145		161,736

- 38 -

Table of


	Six Months Ended June 30,				Change from
	2021		2020		2020
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	37,819	$	36,385	$	1,434
Affiliates—intermediate pipelines	15,027		14,949		78
Affiliates—crude pipelines	38,705		39,704		(999)
	91,551		91,038		513
Third parties—refined product pipelines	19,389		23,548		(4,159)
Third parties—crude pipelines	23,887		14,840		9,047
	134,827		129,426		5,401
Terminals, tanks and loading racks:
Affiliates	65,995		66,496		(501)
Third parties	9,074		7,282		1,792
	75,069		73,778		1,291

Refinery processing units—Affiliates	43,522		39,457		4,065

Total revenues	253,418		242,661		10,757
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	83,433		69,718		13,715
Depreciation and amortization	50,068		49,012		1,056
General and administrative	5,815		5,237		578
Goodwill impairment	11,034		—		11,034
	150,350		123,967		26,383
Operating income	103,068		118,694		(15,626)
Other income (expense):
Equity in earnings of equity method investments	5,186		3,870		1,316
Interest expense, including amortization	(27,178)		(31,546)		4,368
Interest income	13,162		5,031		8,131
Loss on early extinguishment of debt	—		(25,915)		25,915
Gain on sales-type leases	24,677		33,834		(9,157)
Gain on sale of assets and other	5,917		974		4,943
	21,764		(13,752)		35,516
Income before income taxes	124,832		104,942		19,890
State income tax expense	(64)		(76)		12
Net income	124,768		104,866		19,902

Allocation of net income attributable to noncontrolling interests	(4,626)		(3,535)		(1,091)
Net income attributable to the partners	120,142		101,331		18,811


Limited partners’ earnings per unit—basic and diluted	$	1.14	$	0.96	$	0.18
Weighted average limited partners’ units outstanding	105,440		105,440		—
EBITDA (1)	$	184,290	$	176,934	$	7,356
Adjusted EBITDA (1)	$	176,196	$	171,276	$	4,920
Distributable cash flow (2)	$	139,899	$	136,164	$	3,735

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	119,316		115,245		4,071
Affiliates—intermediate pipelines	129,573		135,288		(5,715)
Affiliates—crude pipelines	255,730		278,801		(23,071)
	504,619		529,334		(24,715)
Third parties—refined product pipelines	48,298		53,756		(5,458)
Third parties—crude pipelines	129,603		89,027		40,576
	682,520		672,117		10,403
Terminals and loading racks:
Affiliates	368,612		400,911		(32,299)
Third parties	49,526		45,910		3,616
	418,138		446,821		(28,683)
Refinery processing units—Affiliates	68,688		59,843		8,845
Total for pipelines and terminal and refinery processing unit assets (bpd)	1,169,346		1,178,781		(9,435)

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Table of

(1)Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to ~~include~~ the ~~combined results~~partners plus (i) interest expense, net of interest income, (ii) state income tax expense and (iii) depreciation and amortization. Adjusted EBITDA is calculated as EBITDA plus (i) loss on early extinguishment of debt, (ii) goodwill impairment and (iii) pipeline tariffs not included in revenues due to impacts from lease accounting for certain pipeline tariffs minus (iv) gain on sales-type leases, (v) gain on significant asset sales, and (vi) pipeline lease payments not included in operating costs and expenses. Portions of our ~~Predecessor. See Note 1~~minimum guaranteed pipeline tariffs for assets subject to sales-type lease accounting are recorded as interest income with the ~~Consolidated Financial Statements of HEP for discussion of the basis of this presentation~~

Three Months Ended September 30, Change from
2017 2016 2016
(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines $ 20,801
$ 19,227
$ 1,574
Affiliates—intermediate pipelines 7,832
6,628
1,204
Affiliates—crude pipelines 14,089
17,034
(2,945 )
42,722
42,889
(167 )
Third parties—refined product pipelines 11,350
11,176
174
54,072
54,065
7
Terminals, tanks and loading racks:
Affiliates 31,825
30,322
1,503
Third parties 3,876
4,035
(159 )
35,701
34,357
1,344

Affiliates—refinery processing units 20,591
4,188
16,403

Total revenues 110,364
92,610
17,754
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) 35,998
32,101
3,897
Depreciation and amortization 19,007
18,920
87
General and administrative 3,623
2,664
959
58,628
53,685
4,943
Operating income 51,736
38,925
12,811
Other income (expense):
Equity in earnings of equity method investments 5,072
3,767
1,305
Interest expense, including amortization (14,072 ) (14,447 ) 375
Interest income 101
108
(7 )
Gain on sale of assets and other 155
112
43
(8,744 ) (10,460 ) 1,716
Income before income taxes 42,992
28,465
14,527
State income tax expense 69
(61 ) 130
Net income 43,061
28,404
14,657
Allocation of net loss to Predecessor —
7,547
(7,547 )
Allocation of net income attributable to noncontrolling interests (990 ) (1,166 ) 176
Net income attributable to the partners 42,071
34,785
7,286
General partner interest in net income attributable to the partners ⁽¹⁾
419
(15,222 ) 15,641
Limited partners’ interest in net income $ 42,490
$ 19,563
$ 22,927
Limited partners’ earnings per unit—basic and diluted ⁽¹⁾
$ 0.66
$ 0.33
$ 0.33
Weighted average limited partners’ units outstanding 64,319
59,223
5,096
EBITDA ⁽²⁾
$ 74,980
$ 64,705
$ 10,275
Distributable cash flow ⁽³⁾
$ 59,248
$ 49,257
$ 9,991

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines 142,624
128,020
14,604
Affiliates—intermediate pipelines 151,622
142,417
9,205
Affiliates—crude pipelines 267,911
271,278
(3,367 )
562,157
541,715
20,442
Third parties—refined product pipelines 74,703
73,517
1,186
636,860
615,232
21,628
Terminals and loading racks:
Affiliates 426,122
437,560
(11,438 )
Third parties 69,405
68,276
1,129
495,527
505,836
(10,309 )

Affiliates—refinery processing units 61,453
46,451
15,002

Total for pipelines and terminal and refiney processing unit assets (bpd) 1,193,840
1,167,519
26,321

~~Table of Contentsril 19,~~

Nine Months Ended September 30, Change from
2017 2016 2016
(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines $ 57,977
$ 63,801
$ (5,824 )
Affiliates—intermediate pipelines 20,366
20,821
(455 )
Affiliates—crude pipelines 47,890
53,106
(5,216 )
126,233
137,728
(11,495 )
Third parties—refined product pipelines 35,535
37,376
(1,841 )
161,768
175,104
(13,336 )
Terminals, tanks and loading racks:
Affiliates 93,573
88,825
4,748
Third parties 12,291
12,718
(427 )
105,864
101,543
4,321

Affiliates—refinery processing units 57,510
12,870
44,640

Total revenues 325,142
289,517
35,625
Operating costs and expenses:
Operations (exclusive of depreciation and amortization) 102,584
89,168
13,416
Depreciation and amortization 57,729
51,183
6,546
General and administrative 8,872
8,618
254
169,185
148,969
20,216
Operating income 155,957
140,548
15,409
Other income (expense):
Equity in earnings of equity method investments 10,965
10,155
810
Interest expense, including amortization (41,359 ) (36,258 ) (5,101 )
Interest income 306
332
(26 )
Loss on early extinguishment of debt (12,225 ) —
(12,225 )
Gain on sale of assets 317
104
213
(41,996 ) (25,667 ) (16,329 )
Income before income taxes 113,961
114,881
(920 )
State income tax expense (164 ) (210 ) 46
Net income 113,797
114,671
(874 )
Allocation of net loss to Predecessor —
10,657
(10,657 )
Allocation of net income attributable to noncontrolling interests (4,827 ) (8,448 ) 3,621
Net income attributable to the partners 108,970
116,880
(7,910 )
General partner interest in net income attributable to the partners ⁽¹⁾
(35,047 ) (40,001 ) 4,954
Limited partners’ interest in net income $ 73,923
$ 76,879
$ (2,956 )
Limited partners’ earnings per unit—basic and diluted ⁽¹⁾
$ 1.16
$ 1.29
$ (0.13 )
Weighted average limited partners’ units outstanding 63,845
58,895
4,950
EBITDA ⁽²⁾
$ 220,141
$ 200,678
$ 19,463
Distributable cash flow ⁽³⁾
$ 177,436
$ 160,331
$ 17,105

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines 128,212
128,659
(447 )
Affiliates—intermediate pipelines 136,055
138,346
(2,291 )
Affiliates—crude pipelines 268,736
279,014
(10,278 )
533,003
546,019
(13,016 )
Third parties—refined product pipelines 77,114
75,405
1,709
610,117
621,424
(11,307 )
Terminals and loading racks:
Affiliates 420,979
404,393
16,586
Third parties 68,902
73,653
(4,751 )
489,881
478,046
11,835

Affiliates—refinery processing units 63,858
46,423
17,435

Total for pipelines and terminal and refinery processing unit assets (bpd) 1,163,856
1,145,893
17,963

~~Table of Contentsril 19,~~

September 30,
2017 December 31,
2016
(In thousands)
Balance Sheet Data
Cash and cash equivalents $ 7,476
$ 3,657
Working capital (deficit) $ 5,378
$ (7,782 )
Total assets $ 1,865,842
$ 1,884,237
Long-term debt $ 1,245,066
$ 1,243,912
Partners’ equity ⁽⁵⁾
$ 370,715
$ 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.

~~On October 31, 2017, we closed the restructuring transaction set forth~~remaining amounts recorded as a reduction in the definitive agreement with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HollyFrontier Corporation and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics are canceled, and HEP Logistics' 2% general partner interestnet investment in ~~HEP is converted into a non-economic general partner interest in HEP. In consideration, HEP issued 37,250,000 of its common units to HEP Logistics. Since this transaction closed~~leases. These pipeline tariffs were previously recorded as revenues prior to the ~~record date~~renewal of the throughput agreements, which triggered sales-type lease accounting. Similarly, certain pipeline lease payments were previously recorded as operating costs and expenses, but the underlying lease was reclassified from an operating lease to a financing lease, and these payments are now recorded as interest expense and reductions in the lease liability. EBITDA and Adjusted EBITDA are not calculations based upon generally accepted accounting principles ("GAAP"). However, the amounts included in the EBITDA and Adjusted EBITDA calculations are derived from amounts included in our consolidated financial statements. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income attributable to Holly Energy Partners or operating income, as indications of our operating performance or as alternatives to operating cash flow as a measure of liquidity. EBITDA and Adjusted EBITDA are not necessarily comparable to similarly titled measures of other companies. EBITDA and Adjusted EBITDA are presented here because they are widely used financial indicators used by investors and analysts to measure performance. EBITDA and Adjusted EBITDA are also used by our management for ~~distributions related to third quarter earnings,~~internal analysis and as a basis for ~~purposes~~compliance with financial covenants. Set forth below are our calculations of ~~distributions declared, we did~~EBITDA and Adjusted EBITDA.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)
Net income attributable to the partners	$	55,745	$	76,470	$	120,142	$	101,331
Add (subtract):
Interest expense	13,938		13,779		27,178		31,546
Interest income	(6,614)		(2,813)		(13,162)		(5,031)
State income tax expense	27		39		64		76
Depreciation and amortization	25,003		25,034		50,068		49,012
EBITDA	$	88,099	$	112,509	$	184,290	$	176,934
Loss on early extinguishment of debt	—		—		—		25,915
Gain on sales-type leases	(27)		(33,834)		(24,677)		(33,834)
Gain on significant asset sales	(5,263)		—		(5,263)		—
Goodwill impairment	—		—		11,034		—

Pipeline tariffs not included in revenues	7,058		3,099		14,025		5,474
Lease payments not included in operating costs	(1,606)		(1,606)		(3,213)		(3,213)
Adjusted EBITDA	$	88,261	$	80,168	$	176,196	$	171,276

(2)Distributable cash flow is not ~~include any incentive or regular distributions on~~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 ~~partner interest~~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 ~~the third quarter of 2017.~~

~~(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 September 30, Nine Months Ended September 30,
2017 2016 2017 2016
(In thousands)
Net income attributable to the partners $ 42,071
$ 34,785
$ 108,970
$ 116,880
Add (subtract):
Interest expense 13,291
13,529
39,042
33,964
Interest income (101 ) (108 ) (306 ) (332 )
Amortization of discount and deferred debt issuance costs 781
918
2,317
2,294
Loss on early extinguishment of debt —
—
12,225
—
State income tax expense (69 ) 61
164
210
Depreciation and amortization 19,007
18,920
57,729
51,183
Predecessor depreciation and amortization —
(3,400 ) —
(3,521 )
EBITDA $ 74,980
$ 64,705
$ 220,141
$ 200,678

~~(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

~~Table of Contentsril 19,~~

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.

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Table of


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended June 30,				Six Months Ended June 30,
	2017			2016			2017			2016				2021		2020		2021		2020
	(In thousands)													(In thousands)
Net income attributable to the partners	$	42,071		$	34,785		$	108,970		$	116,880		Net income attributable to the partners	$	55,745	$	76,470	$	120,142	$	101,331
Add (subtract):													Add (subtract):
Depreciation and amortization	19,007			18,920			57,729			51,183			Depreciation and amortization	25,003		25,034		50,068		49,012
Amortization of discount and deferred debt issuance costs	781			918			2,317			2,294			Amortization of discount and deferred debt issuance costs	1,385		842		2,229		1,641
Loss on early extinguishment of debt	—			—			12,225			—			Loss on early extinguishment of debt	—		—		—		25,915
Increase (decrease) in deferred revenue related to minimum revenue commitments	1,134			1,748			3,835			(179		)
Maintenance capital expenditures⁽⁴⁾	(3,240		)	(3,475		)	(6,308		)	(7,797		)
Decrease in environmental liability	(180		)	(277		)	(741		)	(719		)
Customer billings greater than revenue recognized													Customer billings greater than revenue recognized	(3,573)		(44)		(179)		(501)
Maintenance capital expenditures (3)													Maintenance capital expenditures (3)	(4,111)		(1,140)		(5,482)		(3,627)
Increase (decrease) in environmental liability													Increase (decrease) in environmental liability	(78)		157		(234)		158
Decrease in reimbursable deferred revenue	(917		)	(750		)	(2,765		)	(1,906		)	Decrease in reimbursable deferred revenue	(3,502)		(3,005)		(7,516)		(5,805)
Other non-cash adjustments	592			788			2,174			4,096
Predecessor depreciation and amortization	—			(3,400		)	—			(3,521		)
Gain on sales-type leases													Gain on sales-type leases	(27)		(33,834)		(24,677)		(33,834)
Gain on significant asset sales													Gain on significant asset sales	(5,263)		—		(5,263)		—
Goodwill impairment													Goodwill impairment	—		—		11,034		—
Other													Other	1,101		976		(223)		1,874
Distributable cash flow	$	59,248		$	49,257		$	177,436		$	160,331		Distributable cash flow	$	66,680	$	65,456	$	139,899	$	136,164


~~(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.

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


	June 30, 2021		December 31, 2020
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	19,561	$	21,990
Working capital	$	15,367	$	14,247
Total assets	$	2,172,822	$	2,167,565
Long-term debt	$	1,362,570	$	1,405,603
Partners’ equity	$	425,218	$	379,292

Results of Operations—Three Months Ended ~~September~~June 30, ~~2017~~2021 Compared with Three Months Ended ~~September~~June 30, ~~2016~~2020

Summary

Net income attributable to the partners for the ~~third~~second quarter was ~~$42.1~~$55.7 million ($~~0.66~~0.53 per basic and diluted limited partner unit) compared to ~~$34.8~~$76.5 million ($~~0.33~~0.73 per basic and diluted limited partner unit) for the ~~third~~second quarter of ~~2016.~~2020. Results for the second quarter of 2021 reflect a gain on significant asset sales of $5.3 million related to the sale of a 6-inch refined product pipeline that connected HFC’s Navajo refinery to terminals in El Paso for gross proceeds of $7.0 millon. Net income attributable to HEP for the second quarter of 2020 included a gain on sales-type leases of $33.8 million. Excluding these items, net income attributable to the partners for the second quarters of 2021 and 2020 were $50.5 million ($0.48 per basic and diluted limited partner unit) and $42.6 million ($0.40 per basic and diluted limited partner unit), respectively. The increase in earnings ~~is primarily~~was mainly due to ~~increased operating~~higher volumes across our pipelines and higher interest income ~~from our Woods Cross refinery processing units of $8.9 million and increased earnings from our equity method investments of $1.3 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 September 30, 2017, include the recognition of $0.7 million of prior shortfalls billed to shippers in 2016 compared to revenues for the three months ended September 30, 2016, which included the recognition of $0.2 million of prior shortfalls billed to shippers in 2015. Additional net shortfall billings of $2.0 million associated with ~~certain guaranteed shipping contracts were deferred during the three months ended~~ ~~September 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.sales-type leases, partially offset by higher operating expenses.

Revenues

Revenues for the second quarter were ~~$110.4~~$126.2 million, an increase of ~~$17.8~~$11.4 million compared to the ~~third~~second quarter of ~~2016 primarily due~~2020. The increase was mainly attributable to revenues of $16.6 million from the Woods Cross refinery processing units acquired in the fourth quarter of 2016. Overall pipeline volumes were up 4% compared to the three months ended September 30, 2016, largely due to ana 14% increase in ~~both refined~~overall crude and product ~~and intermediate~~ pipeline ~~shipments associated with higher production at HFC’s Navajo refinery.~~volumes.

- 41 -

Table of ~~Contentsril 19,~~

Revenues from our refined product pipelines were ~~$32.2~~$28.7 million, an increase of ~~$1.7~~$3.7 million compared to the ~~third~~second quarter of ~~2016, and shipments~~2020. Shipments averaged ~~217.3 mbpd~~171.2 thousand barrels per day (“mbpd”) compared to ~~201.5~~158.4 mbpd for the ~~third~~second quarter of ~~2016. Revenues~~2020. The volume and ~~volumes both increased primarily~~revenue increases were mainly due to higher ~~shipments~~volumes on ~~our New Mexico refined product~~ pipelines ~~in line with increased production at~~servicing HFC's Navajo ~~refinery.~~refinery and our UNEV pipeline.

Revenues from our intermediate pipelines were ~~$7.8~~$7.5 million, consistent with the second quarter of 2020. Shipments averaged 143.8 mbpd for the second quarter of 2021 compared to 128.5 mbpd for the second quarter of 2020. The increase in volumes was mainly due to higher throughputs on our intermediate pipelines servicing HFC's Navajo refinery while revenue remained relatively constant mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $32.1 million, an increase of ~~$1.2~~$5.6 million oncompared to the second quarter of 2020, and shipments ~~averaging 151.6~~averaged 396.7 mbpd compared to ~~142.4~~338.4 mbpd for the ~~third~~second quarter of ~~2016. These~~2020. The revenue and volume increases were ~~principally due~~mainly attributable to ~~increased shipments~~higher volumes on our ~~New Mexico intermediate pipelines~~crude pipeline systems in ~~line with increased production at HFC's Navajo refinery.~~Wyoming and Utah.

Revenues from ~~our~~ ~~crude pipelines~~ were $14.1 million, a decrease of $2.9 million, on shipments averaging 267.9 mbpd compared to 271.3 mbpd for the third quarter of 2016. This revenue decrease is attributable to a $2.9 million one-time reduction in revenue associated with our crude gathering pipelines. This adjustment will have no material impact on revenues going forward.

~~Revenues from~~ terminal, tankage and loading rack fees were ~~$35.7~~$36.9 million, an increase of ~~$1.3~~$0.6 million compared to the ~~third~~second quarter of ~~2016.~~2020. Refined products and crude oil terminalled in the facilities averaged ~~495.5~~466.7 mbpd compared to ~~505.8~~418.0 mbpd for the ~~third~~second quarter of ~~2016.~~2020. The ~~revenue increases are~~volume increase was mainly the result of higher throughputs at HFC's El Dorado refinery. Revenues did not increase in proportion to the increase in volumes mainly due to contractual minimum volume guarantees and lower on-going revenues on our Cheyenne assets as a result of the conversion of the HFC Cheyenne refinery to renewable diesel production.

Revenues from refinery processing units were $21.0 million, an increase of $1.5 million compared to the second quarter of 2020, and throughputs averaged 76.6 mbpd compared to 49.9 mbpd for the second quarter of 2020. The increase in volumes was mainly due to increased ~~reimbursable revenue~~throughput for ~~projects managed by HEP~~both our Woods Cross and ~~reimbursed by HFC.~~

El Dorado processing units. Revenues ~~from~~ ~~refinery processing units~~ ~~were $20.6 million, an increase of $16.4 million on throughputs averaging 61.5 mbpd compared to 46.5 mbpd for the third quarter of 2016. This~~did not increase in ~~revenue and volume is primarily~~proportion to the increase in volumes mainly due to ~~the Woods Cross refinery processing units acquired in the fourth quarter of 2016.~~contractual minimum volume guarantees.

Operations Expense

Operations (exclusive of depreciation and ~~amortization)~~amortization and goodwill impairment) expense was $42.1 million for the three months ended ~~September~~June 30, ~~2017,~~ ~~increased~~ ~~by $3.9~~2021, an increase of $7.3 million compared to the second quarter of 2020. The increase was mainly due to higher pipeline rental costs, natural gas costs, maintenance expense project costs, employee costs, and chemicals and catalysts for the three months ended ~~September~~June 30, ~~2016. The~~ ~~increase is~~ ~~mainly due to an increase in maintenance project costs.~~2021.

Depreciation and Amortization

Depreciation and amortization for the three months ended ~~September~~June 30, ~~2017, increased by $0.1 million~~2021 remained constant compared to the three months ended ~~September~~June 30, ~~2016.~~2020.

General and Administrative

General and administrative costs for the three months ended ~~September~~June 30, ~~2017,~~2021 increased by ~~$1.0~~$0.3 million compared to the three months ended ~~September~~June 30, ~~2016,~~2020, mainly due to higher legal ~~and consulting costs associated with our agreement, pursuant to which~~expenses for the ~~incentive distribution rights held by HEP Logistics have been canceled and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP.~~three months ended June 30, 2021.

Equity in Earnings of Equity Method Investments


	Three Months Ended June 30,
Equity Method Investment	2021		2020
	(in thousands)
Osage Pipe Line Company, LLC	$	914	$	366
Cheyenne Pipeline LLC	1,879		1,085
Cushing Terminal	630		705
Total	$	3,423	$	2,156

Equity in earnings of Osage Pipe Line Company, LLC increased for the three months ended June 30, 2021, mainly due to higher throughput volumes. Equity in earnings of Cheyenne Pipeline LLC increased for the three months ended June 30, 2021, mainly due to the recognition in revenue of prior contractual minimum commitment billings.

- 42 -

Three Months Ended September 30,
Equity Method Investment 2017 2016
(in thousands)
SLC Pipeline LLC $ 1,030
$ 1,283
Frontier Aspen LLC 1,662
586
Osage Pipe Line Company, LLC 1,119
975
Cheyenne Pipeline LLC 1,261
923
Total $ 5,072
$ 3,767

Table of

Interest Expense, including Amortization

Interest expense for the three months ended ~~September~~June 30, ~~2017,~~2021, totaled ~~$14.1~~$13.9 million, ~~a decrease~~an increase of ~~$0.4~~$0.2 million compared to the three months ended ~~September~~June 30, ~~2016.~~2020. Our aggregate effective interest rates were ~~4.5%~~3.8% and ~~5.3%~~3.4% for the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~,2020, respectively.

State Income Tax Expense

We recorded state income tax ~~benefit of~~ ~~$69,000~~ ~~and~~ expense of ~~$61,000~~$27,000 and $39,000 for the three months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively. All tax expense is solely attributable to the Texas margin tax.

~~Table of Contentsril 19,~~

Results of Operations—~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2021 Compared with ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2020

Summary

Net income attributable to ~~Holly Energy Partners~~the partners for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, was ~~$109.0~~$120.1 million ($1.14 per basic and diluted limited partner unit) compared to $101.3 million ($0.96 per basic and diluted limited partner unit) for the six months ended June 30, 2020. Results for the six months ended June 30, 2021, include special items that collectively increased net income attributable to the partners by a total of $18.9 million. These items include a gain on sales-type leases of $24.7 million, a gain on significant asset sales of $5.3 million and a goodwill impairment charge of $11.0 million. In addition, the net income attributable to the partners for the six months ended June 30, 2020, included a gain on sales-type leases of $33.8 million and a loss on early extinguishment of debt of $25.9 million. Excluding these items, net income attributable to the partners for the six months ended June 30, 2021 and 2020, were $101.2 million ($0.96 per basic and diluted limited partner unit) and $93.4 million ($0.89 per basic and diluted limited partner unit), respectively. The increase in earnings was mainly due to higher volumes across our crude pipelines and higher interest income associated with sales-type leases, partially offset by higher operating expenses.

Revenues

Revenues for the six months ended June 30, 2021, were $253.4 million, an increase of $10.8 million compared to ~~$116.9 million for~~ the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2020. The ~~decrease~~increase was mainly attributable to increased volumes on our crude pipeline systems in ~~earnings is primarily due to (a) a charge~~Wyoming and Utah, the recognition of ~~$12.2~~$9.9 million of the $10 million termination fee related to the ~~early redemption~~termination of HollyFrontier's minimum volume commitment on our ~~previously outstanding $300 million, 6.5% Senior Notes (the “6.5% Senior Notes”), due in 2020, (b)~~Cheyenne assets and higher ~~interest expense of $5.1 million, and (c) lower refined product pipeline~~ revenues ~~of $7.7 million offset by (d) earnings from~~on our ~~Woods Cross~~ refinery processing units ~~acquired in the fourth quarter of 2016.~~

Revenues for the nine months ended September 30, 2017, include the recognition of $3.5 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 $7.1 million associated with certain guaranteed shipping contracts were deferred during the nine months ended September 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 nine months ended September 30, 2017, were $325.1 million, a $35.6 million increase compared to the nine months ended September 30, 2016. The increase is primarily attributable to the $44.1 million of revenue recorded for the Woods Cross refinery processing units acquired in the fourth quarter of 2016,partially offset by lower on-going revenues on our Cheyenne assets as well as a ~~$9.8 million decrease in revenues around assets serving HFC's Navajo refinery primarily due~~reclassification of certain income from revenue to ~~the substantial turnaround at the Navajo refinery during the first quarter of 2017. Overall pipeline volumes were down 1.8% compared to the nine months ended September 30, 2016.~~interest income under sales-type lease accounting.

Revenues from our refined product pipelines were ~~$93.5~~$57.2 million, a decrease of ~~$7.7~~$2.7 million ~~on shipments averaging 205.3~~compared to the six months ended June 30, 2020. Shipments averaged 167.6 mbpd compared to ~~204.1~~169.0 mbpd for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~ 2020. The ~~decrease in revenues is primarily~~volume and revenue decreases were mainly due to lower volumes on ~~product~~ pipelines servicing Delek's Big Spring refinery. Revenue also decreased due to ~~the turnaround at HFC's Navajo refinery in the first quarter~~a reclassification of ~~2017 as well as a higher amount of shortfalls recognized in~~certain pipeline income from revenue ~~for the nine months ended September 30, 2016.~~to interest income under sales-type lease accounting.

Revenues from our intermediate pipelines were ~~$20.4~~$15.0 million, ~~a decrease~~an increase of ~~$0.5~~$0.1 million ~~on shipments averaging 136.1~~compared to the six months ended June 30, 2020. Shipments averaged 129.6 mbpd compared to ~~138.3~~135.3 mbpd for the ~~nine~~six months ended ~~September~~June 30, ~~2016. These volume decreases were primarily~~2020. The decrease in volumes was mainly due to ~~the turnaround at~~lower throughputs on our intermediate pipelines servicing HFC's ~~Navajo~~Tulsa refinery ~~which was partially offset by increases in production at the Navajo refinery after the turnaround.~~while revenue remained relatively constant mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were ~~$47.9~~$62.6 million, ~~a decrease~~an increase of ~~$5.2~~$8.0 million ~~on shipments averaging 268.7~~compared to the six months ended June 30, 2020. Shipments averaged 385.3 mbpd compared to ~~279.0~~367.8 mbpd for the ~~nine~~six months ended ~~September~~June 30, ~~2016. Revenues and~~2020. The increases were mainly attributable to increased volumes ~~decreased principally due to HFC's Navajo refinery turnaround in the first quarter of 2017, a decrease in deferred revenue recognized and the one-time adjustment associated with~~on our crude ~~gathering lines made~~pipeline systems in ~~the third quarter of 2017.~~Wyoming and Utah.

Revenues from terminal, tankage and loading rack fees were ~~$105.9~~$75.1 million, an increase of ~~$4.3~~$1.3 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2020. Refined products and crude oil terminalled in the facilities averaged ~~489.9~~418.1 mbpd compared to ~~478.0~~446.8 mbpd for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~ 2020. The volume ~~and revenue increases are~~decrease was mainly the result of lower throughputs at HFC's Tulsa refinery as well as the cessation of petroleum refinery operations at HFC's Cheyenne refinery. Revenues increased mainly due to ~~our Tulsa crude tanks acquired on~~ the ~~last day~~recognition of $9.9 million of the ~~first quarter~~$10 million termination fee related to the termination of ~~2016~~HFC's minimum volume commitment on our Cheyenne assets partially offset by ~~the transfer~~lower on-going revenues on our Cheyenne assets as a result of the ~~El Paso terminal~~conversion of the HFC Cheyenne refinery to ~~HollyFrontier in the first quarter~~renewable diesel production as well as a reclassification of ~~2016.~~certain income from revenue to interest income under sales-type lease accounting.

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Table of

Revenues fromrefinery processing units were ~~$57.5~~$43.5 million, an increase of ~~$44.6~~$4.1 million ~~on throughputs averaging 63.9~~compared to the six months ended June 30, 2020. Throughputs averaged 68.7 mbpd compared to ~~46.4~~59.8 mbpd for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~ 2020. The ~~increases~~increase in ~~revenue and volume is primarily~~volumes was mainly due to ~~the~~increased throughput for both our Woods Cross ~~refinery~~and El Dorado processing ~~units acquired in the fourth quarter~~units. Revenues increased mainly due to higher recovery of ~~2016.~~natural gas costs as well as higher throughputs.

Operations Expense

Operations expense (exclusive of depreciation and amortization) for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, increased by ~~$13.4~~$13.7 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2020. The increase ~~is primarily~~was mainly due to ~~operating expenses for our newly acquired Woods Cross refinery processing units.~~higher maintenance, natural gas, and pipeline rental costs, partially offset by lower materials and supplies and property taxes.

~~Table of Contentsril 19,~~

Depreciation and Amortization

Depreciation and amortization for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, increased by ~~$6.5~~$1.1 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2020. The increase iswas mainly due to the acceleration of depreciation ~~from the Woods Cross refinery processing units acquired in the fourth quarter~~on certain of ~~2016.~~our Cheyenne tanks.

General and Administrative

General and administrative costs for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, increased ~~$0.3~~by $0.6 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2020 mainly due to higher legal ~~and consulting costs offset by decreased employee compensation.~~expenses incurred in the six months ended June 30, 2021.

Equity in Earnings of Equity Method Investments


	Six Months Ended June 30,
Equity Method Investment	2021		2020
	(in thousands)
Osage Pipe Line Company, LLC	1,636		1,380
Cheyenne Pipeline LLC	1,774		2,160
Cushing Terminal	1,776		330
Total	$	5,186	$	3,870

Equity in earnings of Cushing Terminal increased for the ~~first~~six months ended June 30, 2021 as the terminal started operations in the second 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 the decrease in SLC Pipeline LLC earnings.2020.

Nine Months Ended September 30,
Equity Method Investments 2017 2016
(in thousands)
SLC Pipeline LLC $ 2,053
$ 3,397
Frontier Aspen, LLC 3,813
3,049
Osage Pipe Line Company, LLC 1,889
2,423
Cheyenne Pipeline LLC 3,210
1,286
Total $ 10,965
$ 10,155

Interest Expense, including Amortization

Interest expense for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, totaled ~~$41.4~~$27.2 million, ~~an increase~~a decrease of ~~$5.1~~$4.4 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2020. The ~~increase is primarily~~decrease was mainly due to ~~the $400~~market interest rate decreases under our senior secured revolving credit facility and refinancingour $500 million ~~6% Senior Notes issued July 19, 2016, and a higher average balance outstanding on the Credit Agreement.~~aggregate principal amount of 6.0% senior notes due 2024 with $500 million aggregate principal amount of 5.0% senior notes due 2028. Our aggregate effective interest rates were ~~4.4%~~3.6% and ~~4.6%~~4.0% for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, 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 Expense

We recorded state income tax expense of ~~$164,000~~$64,000 and ~~$210,000~~$76,000 for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, respectively. All tax expense is solely attributable to the Texas margin tax.

LIQUIDITY AND CAPITAL RESOURCES

Overview

~~We have a $1.4 billion~~In April 2021, we amended our senior secured revolving credit facility (the “Credit Agreement”) ~~expiring in~~decreasing the size of the facility from $1.4 billion to $1.2 billion and extending the maturity date to July ~~2022.~~27, 2025. 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~~continues to provide for an accordion feature ~~giving~~that allows us ~~the ability~~ to increase commitments under the ~~size of the facility by~~Credit Agreement up to ~~$300 million with additional lender commitments.~~a maximum amount of $1.7 billion.

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Table of

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, we received advances totaling ~~$628~~$141.0 million and repaid ~~$431 million, resulting in a net increase of $197~~$184.5 million under the Credit Agreement, resulting in a net decrease of $43.5 million and an outstanding balance of ~~$750~~$870.0 million at ~~September~~June 30, ~~2017. We~~2021 under the Credit Agreement. As of June 30, 2021, we have no letters of credit outstanding under the Credit Agreement ~~at September 30, 2017,~~ and the available capacity under the Credit Agreement ~~is $650 million at September 30, 2017.~~was $330.0 million. Amounts repaid under ~~our credit facility~~the Credit Agreement 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

~~Table of Contentsril 19,~~

commitments under the Credit Agreement. We do not expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

On ~~September 22, 2017,~~February 4, 2020, we closed a private placement of ~~an additional $100~~$500 million in aggregate principal amount of ~~our 6.0% senior notes for a combined aggregate principal amount outstanding of $500 million maturing~~5% Senior Notes due in ~~2024. The proceeds were used to repay indebtedness outstanding under the Credit Agreement.~~

2028. On ~~January 4, 2017,~~February 5, 2020, we redeemed the ~~$300~~existing $500 million ~~aggregate principal amount of 6.5%~~6% Senior Notes at a redemption cost of ~~$309.8~~$522.5 million, at which time we recognized a ~~$12.2~~$25.9 million early extinguishment loss consisting of a ~~$9.8~~$22.5 million debt redemption premium and unamortized ~~discount and~~ financing costs of ~~$2.4~~$3.4 million. We funded the $522.5 million redemption with proceeds from the issuance of our 5% Senior Notes and 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~~We did not issue any units under this program during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021. As of June 30, 2021, HEP has issued ~~1,538,452~~2,413,153 units under this program, providing approximately $52.3 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 September 30, 2017, HEP has issued 2,241,907 units under this program, providing $77.1$82.3 million in gross proceeds.

Under our registration statement filed with the ~~SEC~~Securities and Exchange Commission (“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~~are expected to 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 sources of liquidity, including cash balances, future internally generated funds, any future issuances of debt or equity securities and funds available under the Credit Agreement will provide sufficient resources to meet our working capital liquidity, capital expenditure and quarterly distribution needs for the foreseeable ~~future.~~future, including funding the cash portion of the HEP Transactions with Sinclair.

In ~~February,~~ May ~~and August,~~2021, we paid a regular quarterly cash ~~distributions~~distribution of ~~$0.6075, $0.6200 and $0.6325, respectively,~~$0.35 on all units in an aggregate amount of ~~$171.6 million including $49.7 million of incentive distribution payments to our general partner.~~$37.0 million.

Cash and cash equivalents ~~increased~~decreased by ~~$3.8~~$2.4 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~.2021. The cash flows provided by operating activities of ~~$177.5~~$162.1 million were ~~greater~~less than the cash flows used for financing activities of ~~$145.0~~$115.6 million and investing activities of ~~$28.7~~$48.9 million. Working capital increased by ~~$13.2~~$1.1 million to ~~$5.4~~$15.4 million at ~~September~~June 30, ~~2017,~~2021, from ~~a negative $7.8~~$14.2 million at December 31, ~~2016.~~2020.

Cash Flows—Operating Activities

Cash flows from operating activities ~~decreased~~ increased by ~~$0.5~~$27.5 million from ~~$178.0~~$134.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2020, to ~~$177.5~~$162.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2021. The increase was mainly due to higher cash receipts from customers and lower payments for interest expenses during the six months ended June 30, 2021, as compared to the six months ended June 30, 2020.

Cash Flows—Investing Activities

Cash flows used for investing activities were ~~$28.7~~$48.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, compared to ~~$137.1~~$31.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016, a decrease~~2020, an increase of ~~$108.5~~$17.1 million. During the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~2020, we invested $59.4 million and $30.7 million, ~~and $48.2 million~~respectively, in additions to properties and ~~equipment, respectively. During the nine months ended September 30, 2017 and 2016, we also~~equipment. We received ~~$1.2~~$3.1 million ~~and $1.7 million for distributions~~ in excess of equity in earnings and $7.3 million in proceeds from the sale of ~~equity investments, respectively. Additionally, we have retrospectively adjusted our historical financial results for~~assets during the ~~nine~~six months ended ~~September~~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 $47.9 million for the Woods Cross refinery processing units and $42.6 million for the purchase of a 50% interest in the Cheyenne Pipeline during the nine months ended September 30, 2016.2021.

- 45 -

Table of ~~Contentsril 19,~~

Cash Flows—Financing Activities

Cash flows used for financing activities were ~~$145.0~~$115.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, compared to ~~$48.7~~$97.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2020, an increase of ~~$96.3~~$18.5 million. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, we received ~~$628.0~~$141.0 million and repaid ~~$431.0~~$184.5 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 net proceeds of $101.8 million from the issuance of our additional 6% Senior Notes and $52.3 million from the issuance of common units under our continuous offering program. Additionally, we paid ~~$171.6~~$75.4 million in regular quarterly cash distributions to our ~~general and~~ limited partners and ~~$5.0~~$5.9 million to our noncontrolling ~~interest.~~interests. We received $17.6 million in contributions from noncontrolling interests during the six months ended June 30, 2021. During the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2020, we ~~paid $39.5 million for the crude oil tanks located at HFC’s Tulsa refinery acquired in March 2016. We~~ received ~~$310.5~~$168.0 million and repaid ~~$642.5~~$138.5 million in advances under the Credit Agreement. We paid ~~$138.8~~$103.0 million in regular quarterly cash distributions to our ~~general and~~ limited partners, and distributed ~~$3.8~~$4.0 million to our noncontrolling ~~interest, and paid $3.9 million in deferred financing charges to amend our credit agreement.~~interests. We also received net proceeds of ~~$394~~$491.3 million ~~from the~~for issuance of our 6%5% Senior Notes and ~~$22.8~~paid $522.5 million ~~from the issuance of common units under~~to retire our ~~continuous offering program.~~6% Senior Notes. In addition, we received ~~$55.0~~$13.3 million ~~for Woods Cross processing units expenditures~~in contributions from ~~HFC.~~noncontrolling interests during the six months ended June 30, 2020.

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. ~~We are forecasting~~Our current 2021 capital forecast is comprised of approximately $17 million to ~~spend $9~~$21 million for maintenance capital expenditures, $5 million to $8 million for refinery unit turnarounds and ~~approximately $37~~$38 million to $42 million for expansion capital expenditures ~~in 2017.~~and our share of Cushing Connect Joint Venture investments. We expect the majority of the 2021 expansion capital ~~budget~~ to be invested in ~~refined product pipeline expansions, crude system enhancements, new storage tanks, and enhanced blending capabilities at~~ our ~~racks.~~share of Cushing Connect Joint Venture investments. 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 planned 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.operations.

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.

~~Table of Contentsril 19,~~

Credit Agreement

~~We have a~~In April 2021, we amended our Credit Agreement decreasing the commitments under the facility from $1.4 billion ~~senior secured revolving credit facility (the “Credit Agreement”) expiring in~~to $1.2 billion and extending the maturity date to July ~~2022.~~27, 2025. 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~~continues to provide for an accordion feature ~~giving~~that allows us ~~the ability~~ to increase the ~~size of~~commitments under the ~~facility by~~Credit Agreement up to ~~$300 million with additional lender commitments.~~a maximum amount of $1.7 billion.

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Table of

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.

Senior Notes

~~On January 4, 2017,~~As of June 30, 2021, we ~~redeemed the $300~~had $500 million in aggregate principal amount of ~~our 6.5%~~5% Senior Notes due in 2028.

On February 4, 2020, we closed a private placement of $500 million in aggregate principal amount of 5% Senior Notes due in 2028. On February 5, 2020, we redeemed the existing $500 million 6% Senior Notes at a redemption cost of ~~$309.8~~$522.5 million, at which time we recognized a ~~$12.2~~$25.9 million early extinguishment loss consisting of a ~~$9.8~~$22.5 million debt redemption premium and unamortized ~~discount and~~ financing costs of ~~$2.4~~$3.4 million. We funded the $522.5 million redemption with proceeds from the issuance of our 5% Senior Notes and borrowings under our Credit Agreement.

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

Indebtedness under the 6%5% Senior Notes is guaranteed by all of our existing wholly-owned ~~subsidiaries.~~subsidiaries (other than Holly Energy Finance Corp. and certain immaterial subsidiaries).

Long-term Debt

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


	September 30, 2017			December 31, 2016				June 30, 2021		December 31, 2020
	(In thousands)							(In thousands)
Credit Agreement	$	750,000		$	553,000		Credit Agreement	$	870,000	913,500

6% Senior Notes
5% Senior Notes							5% Senior Notes
Principal	500,000			400,000			Principal	500,000		500,000
Unamortized debt issuance costs	(4,934		)	(6,607		)	Unamortized debt issuance costs	(7,430)		(7,897)
	495,066			393,393				492,570		492,103
6.5% Senior Notes
Principal	—			300,000
Unamortized discount and debt issuance costs	—			(2,481		)
	—			297,519

Total long-term debt	$	1,245,066		$	1,243,912		Total long-term debt	$	1,362,570	$	1,405,603

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

~~Table of Contentsril 19,~~

Contractual Obligations

There were no significant changes to our long-term contractual obligations during ~~this period.~~the quarter ended June 30, 2021.

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 ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016. Historically, the~~ 2020. PPI has increased an average of ~~0.2%~~0.9% annually over the past five calendar years, including a decrease of ~~1.0%~~1.4% in ~~2016.~~2020 and an increase of 0.8% in 2019. PPI for the first six months of 2021 increased by 6.0% over the first six months of 2020.

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

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provisions that limit the level of annual PPI percentage rate increases or ~~decreases.~~decreases, and the majority of our rates do not decrease when PPI is negative. A significant and prolonged period of high inflation or a significant and prolonged period of negative inflation could adversely affect our cash flows and results of operations if costs increase at a rate greater than the fees we charge our shippers.

Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. ~~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~~Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from ~~Alon~~Delek in 2005, under which ~~Alon~~Delek will indemnify us subject to certain monetary and time limitations.

There are environmental remediation projects in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities retained by HFC. At ~~September~~June 30, ~~2017,~~2021, we ~~have~~had an accrual of ~~$6.4~~$4.3 million that ~~relates~~related 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~~.2020. 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~~.2021. 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.

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Accounting Pronouncements Adopted During the Periods Presented

~~Earnings Per Unit~~Credit Losses Measurement

In ~~April 2015, an accounting standard update~~June 2016, ASU 2016-13, “Measurement of Credit Losses on Financial Instruments,” was issued requiring ~~changes to~~measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the ~~allocation of the earnings or losses of a transferred business for periods before the~~reporting date ~~of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating~~based on historical ~~earnings per unit. We adopted this~~experience, current conditions and reasonable and supportable forecasts. 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 $7.5 million and $10.7 million for the three and nine months ended September 30, 2016, respectively. These reductions had no impact on the historical earnings per unit as they were allocated to the general partner.

~~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~~2020. Adoption 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 willdid not have a material impact on our financial condition, or results of ~~operations.~~operations or cash flows.

~~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.

RISK MANAGEMENT

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

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.

~~Table of Contentsril 19,~~

At ~~September~~June 30, ~~2017~~,2021, we had an outstanding principal balance of $500 million on our 6%5% Senior Notes. A change in interest rates generally would affect the fair value of the 6%5% Senior Notes, but not our earnings or cash flows. At ~~September~~June 30, ~~2017~~,2021, the fair value of our 6%5% Senior Notes was ~~$524.4~~$512.2 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6%5% Senior Notes at ~~September~~June 30, ~~2017~~,2021 would result in a change of approximately ~~$15~~$13.2 million in the fair value of the underlying 6%5% Senior Notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At ~~September~~June 30, ~~2017~~,2021, borrowings outstanding under the Credit Agreement were ~~$750~~$870.0 million. A hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.

Our operations are subject to normal hazards of operations, including but not limited to fire, explosion, cyberattacks and weather-related perils. We maintain various insurance coverages, including property damage, business interruption and cyber insurance, subject to certain ~~deductibles.~~deductibles and insurance policy terms and conditions. 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~~

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.”~~2020.

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.

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~~Item 4.~~	~~Controls and Procedures~~

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~~SEC’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 ~~September~~June 30, ~~2017~~,2021, at a reasonable level of assurance.

(b) Changes in internal control over financial reporting

~~There~~During the three months ended June 30, 2021, there have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION


~~Item 1.~~	~~Legal Proceedings~~

Item 1.Legal Proceedings

~~We are a~~

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


~~Item 1A.~~	~~Risk Factors~~

Item 1A.Risk Factors

~~There~~

Except for the risk factors below, 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.~~2020. In addition to the other information set forth in this quarterly report, you should consider carefully the ~~factors~~information discussed in our ~~2016~~2020 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our ~~2016~~2020 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.

The pending HEP Transactions may not be consummated on a timely basis or at all.Failure to complete the acquisition within the expected timeframe or at all could adversely affect our common unit price and our future business and financial results.

On August 2, 2021, we entered into the Contribution Agreement with Sinclair and certain other parties thereto to acquire all of the issued and outstanding capital stock of STC. We expect the acquisition to close in mid-2022. The HEP Transactions are subject to closing conditions. If these conditions are not satisfied or waived, the acquisition will not be consummated. If the closing of the HEP Transactions is substantially delayed or do not occur at all, or if the terms of the acquisition are required to be modified substantially, we may not realize the anticipated benefits of the acquisition fully or at all, or they may take longer to realize than expected. The closing conditions include, among others, the absence of a law or order prohibiting the transactions contemplated by the business combination agreement and the termination or expiration of any waiting periods under the Hart-Scott Rodino Act, as amended, with respect to the acquisition. We will also incur substantial transaction costs whether or not the acquisition is completed. Any failure to complete the HEP Transactions could have a material adverse effect on our common unit price, our competitiveness and reputation in the marketplace, and our future business and financial results, including our ability to execute on our strategy to return capital to our unitholders that was described in our press release and investor presentation announcing the HEP Transactions.

The anticipated benefits of our pending HEP Transactionsmay not be realized fully or at all or may take longer to realize than expected.

The HEP Transactions will require management to devote significant attention and resources to integrating the Sinclair business with our business. Potential difficulties that may be encountered in the integration process include, among others:

a.the inability to successfully integrate the Sinclair business into the HEP business in a manner that permits us to achieve the full revenue and cost savings anticipated from the Sinclair Transactions;

b.complexities associated with managing the larger, integrated business;

c.potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the acquisition;

d.integrating personnel from the two companies while maintaining focus on providing consistent, high-quality products and services;

e.loss of key employees;

f.integrating relationships with customers, vendors and business partners;

g.performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the acquisition and integrating Sinclair’s operations into HEP; and

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h.the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

Delays or difficulties in the integration process could adversely affect our business, financial results, financial condition and common unit price. Even if we are able to integrate our business operations successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect from this integration or that these benefits will be achieved within the anticipated time frame.

The actual value of the consideration we will pay to Sinclair may exceed the value allocated to such consideration at the time we entered into the Contribution Agreement.

Under the Contribution Agreement, at closing, we will pay Sinclair a cash payment of $325 million and issue Sinclair 21 million common units, which represents a transaction value of approximately $758 million based on the closing price of our common units on July 30, 2021. Neither we nor the Sinclair stockholders are permitted to “walk away” from the transaction solely because of changes in the market price of our common units between the signing of the Contribution Agreement and the closing. Our common units have historically experienced volatility. Common unit price changes may result from a variety of factors that are beyond our control, including changes in our business, operations and prospects, regulatory considerations and general market and economic conditions. The closing price of our common units on the New York Stock Exchange on July 30, 2021, was $20.60; and on August 5, 2021, the closing price of our common units was $17.75. The value of the common units we issue in connection with the closing of the Sinclair Transactions may be significantly higher at the closing than when we entered into the Contribution Agreement.

We will issue a large number of common units in connection with the HEP Transactions, which will result in dilution to our existing unitholders and may cause the market price of our common units to decline in the future as the result of sales of our common units owned by Sinclair stockholders or current HEP unitholders. Our unitholders may not realize a benefit from the Sinclair Transactions commensurate with the ownership dilution they will experience.

At the closing of the HEP Transactions, we will issue 21 million common units to Sinclair. Our issuance of such common units will result in dilution of our existing unitholders’ ownership interests and may also have an adverse impact on our net income per unit in fiscal periods that include (or follow) the closing. The Unitholders Agreement (the “Unitholders Agreement”) between HEP, its ultimate general partner, certain other parties, and the stockholders of Sinclair (the “Sinclair Parties”) also subjects 15.75 million of the HEP common limited partner units issued to the Sinclair Parties (the “Restricted Units”) to a “lock-up” period commencing on the closing date, during which the Sinclair Parties will be prohibited from selling the Restricted Units, except for certain permitted transfers. One-third of such Restricted Units will be released from such restrictions on the date that is six months after the closing, one-third of the Restricted Units will be released from such restrictions on the first anniversary of the closing date, and the remainder will be released from such restrictions on the date that is 15 months from the closing date. In addition, the Unitholders Agreement contains customary registration rights, requiring us to file, within five business days following the closing date, a shelf registration statement on Form S-3 under the Securities Act, to permit the public resale of all the registrable securities held by the Sinclair Parties once such securities are no longer subject to a lock-up.

Following their receipt of common units as consideration in the HEP Transactions, subject to release from the associated lock-up provisions and the filing of a resale registration statement or satisfaction of the requirements of Rule 144, the Sinclair Parties may seek to sell the common units delivered to them. Other HEP unitholders may also seek to sell our common units held by them following, or in anticipation of, completion of the HEP Transactions. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of common units, may affect the market for, and the market price of, our common units in an adverse manner.

If we are unable to realize the strategic and financial benefits currently anticipated from the Sinclair Transactions, our unitholders will have experienced dilution of their ownership interest without receiving commensurate benefit, and we may be unable to execute on our strategy to return capital to our unitholders that was described in our press release and investor presentation announcing the Sinclair Transactions.

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Potential litigation relating to the Sinclair Transactions could result in substantial costs to HEP.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert the time and resources of management. An adverse judgment could result in monetary damages, which could have a negative impact on HEP's liquidity and financial condition.


~~Item 6.~~	~~Exhibits~~

Item 6.Exhibits

The Exhibit Index beginning on page 4954 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of ~~the~~this Quarterly Report on Form 10-Q.

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Table of ~~Contentsril 19,~~

Exhibit Index


Exhibit Number			Description

~~Exhibit~~ ~~Number~~ 2.1†			~~Description~~

~~2.1~~	~~Membership Interest Purchase~~Contribution Agreement, ~~between Plains Pipeline, L.P. and HEP Casper SLC LLC,~~ dated as of August ~~7, 2017~~2, 2021, by and among Holly Energy Partners, L.P., The Sinclair Companies, and Sinclair Transportation Company (incorporated by reference to Exhibit 2.1 of ~~the~~ Registrant’s Current Report on Form 8-K ~~dated~~filed on August ~~10, 2017,~~3, 2021, File No. ~~1-3225)~~1-32225).
~~2.2~~3.1			Membership Interest Purchase Agreement, dated as of August 7, 2017, between Rocky Mountain Pipeline System LLC and HEP SLC, LLC (incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K dated August 10, 2017, File No. 1-3225).
2.3*	~~Amendment to the Membership Interest Purchase Agreement, dated as of September 6, 2017, by and between Rocky Mountain Pipeline System LLC and HEP SLC LLC~~
~~2.4~~	Equity Restructuring Agreement, dated as of October 18, 2017, by and between HEP Logistics Holdings, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K dated October 19, 2017, File No. 1-3225).
~~3.1~~	~~First~~Second 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,~~filed on November 1, 2017, File No. 1-32225).
~~3.5~~3.2			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~~	Limited Partial Waiver of Incentive Distribution Rights under the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated as of August 7, 2017 (incorporated by reference to Exhibit 2.3 of the Registrant’s Current Report on Form 8-K dated August 10, 2017, File No. 1-3225).
~~3.8~~	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~~the quarterly period ended June 30, 2004, File No. 1-32225).
~~3.9~~3.3			First Amended and Restated Agreement of Limited Partnership of HEP Logistics Holdings, L.P. (incorporated by reference to Exhibit 3.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
~~3.10~~3.4			First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 3.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
~~3.11~~3.5			Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C., dated April 27, 2011 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report ~~dated~~filed on May 3, 2011, File No. 1-32225).
~~3.12~~3.6			First Amended and Restated Limited Liability Company Agreement of HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 3.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
~~4.1~~10.1			~~Second Supplemental Indenture, dated July 26, 2017,~~First Amendment to Seventh Amended and Restated Master Throughput Agreement, entered into as of April 30, 2021, effective as of April 1, 2021 by and ~~among~~between HollyFrontier Refining & Marketing LLC and 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. (Incorporated~~Partners - Operating, L.P. (incorporated by reference to Exhibit ~~4.1~~10.9 of ~~the~~ Registrant’s Quarterly Report on Form 10-Q for the ~~fiscal~~ quarter ended ~~June 30, 2017,~~March 31, 2021, File No. ~~1-3225)~~1-32225).
10.1*		First Amendment to Fourth Amended and Restated Master Lease and Access Agreement, dated as of October 13, 2017 by and among certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier Corporation.

~~Table of Contentsril 19,~~


10.2†
~~10.2~~	Amendment No. 1 to Third Amended and Restated Credit Agreement dated ~~July 26, 2017, by and~~April 30, 2021, among ~~the Registrant,~~Holly Energy Partners, L.P., as borrower, certain of its affiliates, as guarantors, Wells Fargo Bank, National Association, as administrative agent, an issuing bank and a lender, and certain other ~~leaders~~lenders party thereto (incorporated by reference to Exhibit 10.1 of ~~the Registrants’~~Registrant’s Current Report on Form 8-K ~~dated July 31, 2017,~~filed on May 3, 2021, File ~~no. 1-32225)~~No.1-32225).
~~10.3~~10.3*		Second Amendment to ~~Equity Distribution~~Seventh Amended and Restated Master Throughput Agreement, entered into as of July 27 , 2021, effective as of May 1, 2021, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners – Operating L.P.
10.4†		Unitholders Agreement, dated as of ~~July 28, 2017,~~August 2, 2021, by and among ~~the Registrant, HEP Logistics Holdings,~~Holly Energy Partners, L.P., Holly ~~Logistics~~Logistic Services, L.L.C., Navajo Pipeline Co., L.P., The Sinclair Companies, and ~~Citigroup Global Markets Inc., Goldman, Sachs & Co., and Merrill Lynch, Pierce, Fenner & Smith Incorporated. (Incorporated by reference~~the unitholders set forth on Schedule I thereto, as may be amended from time to ~~Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2017, File No. 1-3225)~~.
~~10.4~~	Purchase Agreement, dated September 19, 2017, among the Registrant, Holly Energy Finance Corp., and each of the guarantors party thereto and Citigroup Global Markets Inc., as representative of the initial purchasers named thereintime (incorporated by reference to Exhibit 10.1 of ~~the Registrants’~~Registrant’s Current Report on Form 8-K ~~dated September 25, 2017,~~filed on August 3, 2021, File ~~no. 132225)~~No. 1-32225).
31.1*10.5		Letter Agreement, dated as of August 2, 2021, by and among HollyFrontier Corporation and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed on August 3, 2021, File No. 1-32225).
31.1*		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.


101++
~~101++~~	The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended ~~September~~June 30, ~~2017,~~2021 formatted in ~~XBRL (Extensible~~iXBRL (Inline 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)~~(iv) Consolidated Statement of Partners’ Equity, and ~~(vi)~~(v) Notes to Consolidated Financial Statements. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
104		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).

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*		Filed herewith.
**		Furnished herewith.
+		Constitutes management contracts or compensatory plans or arrangements.
++		Filed electronically herewith.
†		Schedules and exhibits have been omitted pursuant to Item 601(a)(5) of regulation S-K. The registrant agrees to furnish supplementally a copy of the omitted schedules and exhibits to the SEC upon request.

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

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

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


			HOLLY ENERGY PARTNERS, L.P.
			(Registrant)

			~~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: ~~November 2, 2017~~August 6, 2021				/s/ ~~Richard L. Voliva III~~John Harrison
				~~Richard L. Voliva III~~John Harrison
				~~Executive~~Senior Vice President, ~~and~~ Chief Financial Officer and Treasurer (Principal Financial Officer)

Date: ~~November 2, 2017~~August 6, 2021				/s/ Kenneth P. Norwood
				Kenneth P. Norwood
				Vice President and Controller (Principal Accounting Officer)

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	FORWARD-LOOKING STATEMENTS				3

PART I. FINANCIAL INFORMATION						45

			Item 1.	Financial Statements (Unaudited)		45

				Consolidated Balance Sheets		45

				Consolidated Statements of Income		56

				~~Consolidated Statements of Comprehensive Income~~		6

		Consolidated Statements of Cash Flows	7

				Consolidated ~~Statement~~Statements of Equity		8

				Notes to Consolidated Financial Statements		9

			Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		3134

			Item 3.	Quantitative and Qualitative Disclosures About Market Risk		4649

			Item 4.	Controls and Procedures		4650

PART II. OTHER INFORMATION						4751

			Item 1.	Legal Proceedings		4751

			Item 1A.	Risk Factors		4751

			Item 6.	Exhibits		4753

				Index to Exhibits		4854

				SIGNATURES		4956



	Nine Months Ended September 30,
	2017			2016 ⁽¹⁾
Cash flows from operating activities
Net income	$	113,797		$	114,671
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	57,729			51,183
(Gain) loss on sale of assets	(269		)	(121		)
Amortization of deferred charges	2,317			2,294
Amortization of restricted and performance units	1,908			1,865
Earnings distributions greater (less) than income from equity investments	513			(1,370		)
Loss on early extinguishment of debt	12,225			—
(Increase) decrease in operating assets:
Accounts receivable—trade	516			1,521
Accounts receivable—affiliates	(191		)	2,971
Prepaid and other current assets	593			814
Increase (decrease) in operating liabilities:
Accounts payable—trade	3,393			(5,757		)
Accounts payable—affiliates	(6,866		)	1,589
Accrued interest	(12,543		)	441
Deferred revenue	3,096			6,288
Accrued property taxes	2,090			3,199
Other current liabilities	(99		)	(1,020		)
Other, net	(750		)	(594		)
Net cash provided by operating activities	177,459			177,974

Cash flows from investing activities
Additions to properties and equipment	(30,675		)	(48,224		)
Purchase of Woods Cross refinery processing units	—			(47,891		)
Purchase of interest in Cheyenne Pipeline	—			(42,550		)
Proceeds from sale of assets	794			210
Distributions in excess of equity in earnings of equity investments	1,224			1,685
Other	—			(351		)
Net cash used for investing activities	(28,657		)	(137,121		)

Cash flows from financing activities
Borrowings under credit agreement	628,000			310,500
Repayments of credit agreement borrowings	(431,000		)	(642,500		)
Proceeds from issuance of Senior Notes	101,750			394,000
Redemption of 6.5% Senior Notes	(309,750		)	—
Proceeds from issuance of common units	52,285			22,791
Distributions to HEP unitholders	(171,560		)	(138,798		)
Distributions to noncontrolling interest	(5,000		)	(3,750		)
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	—			55,027
Contributions from general partner	1,072			470
Purchase of units for incentive grants	—			(784		)
Deferred financing costs	(9,453		)	(3,930		)
Other	(1,224		)	(939		)
Net cash used by financing activities	(144,983		)	(48,658		)

Cash and cash equivalents
Increase (decrease) for the period	3,819			(7,805		)
Beginning of period	3,657			15,013
End of period	$	7,476		$	7,208



	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	52,285			—			—			—			52,285
Contribution from HFC	—			1,072			—			—			1,072
Distribution to HFC for acquisition	—			(103		)	—			—			(103		)
Distributions to HEP unitholders	(118,424		)	(53,136		)	—			—			(171,560		)
Distributions to noncontrolling interest	—			—			—			(5,000		)	(5,000		)
Amortization of restricted and performance units	1,908			—			—			—			1,908
Class B unit accretion	(2,051		)	(42		)	—			—			(2,093		)
Net income	76,016			35,047			—			2,734			113,797
Other comprehensive income	—			—			(91		)	—			(91		)
Balance September 30, 2017	$	520,709		$	(149,994	)	$	—		$	91,291		$	462,006



	Three Months Ended September 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)	$	27,954	$	—	$	4,147	$	32,101
Depreciation and amortization	15,520		—		3,400		18,920
Allocation of net loss attributable to predecessor	—		—		7,547		7,547



	Nine Months Ended September 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)	$	82,131	$	—	$	7,037	$	89,168
Depreciation and amortization	47,780		—		3,403		51,183
Allocation of net loss attributable to predecessor	—		217		10,440		10,657



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	(20,106	)	30.10
Outstanding at September 30, 2017 (nonvested)	124,230		$	33.92



Derivative Instrument	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(In thousands)
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



	General Partner (including IDRs)			Limited Partners’ Common Units			Total
	(In thousands, except per unit data)
Three Months Ended September 30, 2017
Net income attributable to the partners:
Distributions declared	$	—		$	63,012		$	63,012
Distributions in excess of net income attributable to the partners	(419		)	(20,522		)	(20,941		)
Net income attributable to the partners	$	(419	)	$	42,490		$	42,071
Weighted average limited partners' units outstanding				64,319
Limited partners' per unit interest in earnings - basic and diluted				$	0.66

Three Months Ended September 30, 2016
Net income attributable to the partners:
Distributions declared	$	15,888		$	37,354		$	53,242
Distributions in excess of net income attributable to the partners	(369		)	(18,088		)	(18,457		)
Net income attributable to the partners	$	15,519		$	19,266		$	34,785
Weighted average limited partners' units outstanding				59,223
Limited partners' per unit interest in earnings - basic and diluted				$	0.33



Nine Months Ended September 30, 2017	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	258,571		$	18,745		$	—		$	277,316
Third parties	—			32,146			15,680			—			47,826
	—			290,717			34,425			—			325,142
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			91,323			11,261			—			102,584
Depreciation and amortization	—			45,498			12,231			—			57,729
General and administrative	3,070			5,802			—			—			8,872
	3,070			142,623			23,492			—			169,185
Operating income (loss)	(3,070		)	148,094			10,933			—			155,957

Other income (expense):
Equity in earnings (loss) of subsidiaries	165,624			8,203			—			(173,827		)	—
Equity in earnings of equity method investments	—			10,965			—			—			10,965
Interest expense	(41,359		)	—			—			—			(41,359		)
Interest income	—			306			—			—			306
Loss on early extinguishment of debt	(12,225		)	—			—			—			(12,225		)
Gain (loss) on sale of assets and other	—			313			4			—			317
	112,040			19,787			4			(173,827		)	(41,996		)
Income (loss) before income taxes	108,970			167,881			10,937			(173,827		)	113,961
State income tax expense	—			(164		)	—			—			(164		)
Net income (loss)	108,970			167,717			10,937			(173,827		)	113,797
Allocation of net income attributable to noncontrolling interests	—			(2,093		)	(2,734		)	—			(4,827		)
Net income (loss) attributable to Holly Energy Partners	108,970			165,624			8,203			(173,827		)	108,970
Other comprehensive income (loss)	(91		)	(91		)	—			91			(91		)
Comprehensive income (loss)	$	108,879		$	165,533		$	8,203		$	(173,736	)	$	108,879