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 30, 20172021
OR
¨

☐		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to _____________                    
Commission File Number: 1-32225
  

_____________________________________________________________________________________
HOLLY ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
 ______________________________________________________________________________________
Delaware20-0833098
(State or other jurisdiction of

incorporation or organization)
(I.R.S. Employer

Identification No.)
2828 N. Harwood, Suite 1300
Dallas, Texas
75201
Dallas
Texas75201
(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 Section 12(b) of the Securities Exchange Act of 1934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Limited Partner UnitsHEPNew 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, a 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 filerý☒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, 2017,29, 2021, was 64,318,955.105,440,201.


Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.
INDEX
 
FORWARD-LOOKING STATEMENTS
3
45
Item 1.
45
45
56
6
Consolidated Statements of Cash Flows
7
8
910
Item 2.
3135
Item 3.
4650
Item 4.
4651
4752
Item 1.
4752
Item 1A.
4752
Item 6.
4753
4854
4956
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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, thosestatements 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 demand for and supply of crude oil and refined products, including uncertainty regarding the effects of the continuing COVID-19 pandemic on future 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 necessary to complete the Sinclair acquisition on the terms and timeline desired); (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) the cost and potential for delay in closing as a result of litigation against us or HollyFrontier Corporation (“HFC”) challenging the Sinclair transactions;
•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 andpipelines, 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 attacksor 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, our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, 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, 2016September 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: $7,472 and $18,259, respectively)
Cash and cash equivalents (Cushing Connect VIEs: $7,472 and $18,259, respectively)
$12,816 $21,990 
Accounts receivable:    Accounts receivable:
Trade 7,330
 7,846
Trade12,121 14,543 
Affiliates 42,753
 42,562
Affiliates41,507 47,972 
 50,083
 50,408
53,628 62,515 
Prepaid and other current assets 2,295
 2,888
Prepaid and other current assets8,174 9,487 
Total current assets 59,854
 56,953
Total current assets74,618 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: $0 and $47,801, respectively)
Properties and equipment, net (Cushing Connect VIEs: $0 and $47,801, respectively)
1,335,042 1,450,685 
Operating lease right-of-use assets, netOperating lease right-of-use assets, net2,501 2,979 
Net investment in leases (Cushing Connect VIEs: $95,598 and $0, respectively)
Net investment in leases (Cushing Connect VIEs: $95,598 and $0, respectively)
306,071 166,316 
Intangible assets, netIntangible assets, net76,809 87,315 
Goodwill 256,498
 256,498
Goodwill223,650 234,684 
Equity method investments 163,873
 165,609
Equity method investments (Cushing Connect VIEs: $37,691 and $39,456, respectively)
Equity method investments (Cushing Connect VIEs: $37,691 and $39,456, respectively)
117,027 120,544 
Other assets 16,880
 9,926
Other assets16,858 11,050 
Total assets $1,865,842
 $1,884,237
Total assets$2,152,576 $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: $10,083 and $14,076, respectively)
Trade (Cushing Connect VIEs: $10,083 and $14,076, respectively)
$25,472 $28,280 
Affiliates 9,559
 16,424
Affiliates14,605 18,120 
 23,143
 26,942
40,077 46,400 
    
Accrued interest 5,527
 18,069
Accrued interest4,604 10,892 
Deferred revenue 14,827
 11,102
Deferred revenue10,768 11,368 
Accrued property taxes 7,487
 5,397
Accrued property taxes8,877 3,992 
Current operating lease liabilitiesCurrent operating lease liabilities706 875 
Current finance lease liabilitiesCurrent finance lease liabilities3,753 3,713 
Other current liabilities 3,492
 3,225
Other current liabilities2,687 2,505 
Total current liabilities 54,476
 64,735
Total current liabilities71,472 79,745 
    
Long-term debt 1,245,066
 1,243,912
Long-term debt1,333,309 1,405,603 
Noncurrent operating lease liabilitiesNoncurrent operating lease liabilities2,169 2,476 
Noncurrent finance lease liabilitiesNoncurrent finance lease liabilities65,565 68,047 
Other long-term liabilities 15,477
 16,445
Other long-term liabilities12,317 12,905 
Deferred revenue 46,405
 47,035
Deferred revenue30,920 40,581 
    
Class B unit 42,412
 40,319
Class B unit55,593 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 September 30, 2021 and December 31, 2020)
Common unitholders (105,440 units issued and outstanding
at September 30, 2021 and December 31, 2020)
437,998 379,292 
Noncontrolling interestsNoncontrolling interests143,233 126,066 
Total equity 462,006
 471,791
Total equity581,231 505,358 
Total liabilities and equity $1,865,842
 $1,884,237
Total liabilities and equity$2,152,576 $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
September 30,		Nine Months Ended
September 30,
2021202020212020
Revenues:
Affiliates$97,124 $100,992 $298,192 $297,983 
Third parties25,460 26,739 77,810 72,409 
122,584 127,731 376,002 370,392 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)42,793 40,003 126,226 109,721 
Depreciation and amortization21,826 26,190 71,894 75,202 
General and administrative3,849 2,332 9,664 7,569 
Goodwill impairment— 35,653 11,034 35,653 
68,468 104,178 218,818 228,145 
Operating income54,116 23,553 157,184 142,247 
Other income (expense):
Equity in earnings of equity method investments3,689 1,316 8,875 5,186 
Interest expense(13,417)(14,104)(40,595)(45,650)
Interest income6,835 2,803 19,997 7,834 
Gain on sales-type leases— — 24,677 33,834 
Loss on early extinguishment of debt— — — (25,915)
Gain on sale of assets and other77 7,465 5,994 8,439 
(2,816)(2,520)18,948 (16,272)
Income before income taxes51,300 21,033 176,132 125,975 
State income tax benefit (expense)4 (34)(60)(110)
Net income51,304 20,999 176,072 125,865 
Allocation of net income attributable to noncontrolling interests(2,144)(3,186)(6,770)(6,721)
Net income attributable to the partners49,160 17,813 169,302 119,144 
Limited partners’ per unit interest in earnings—basic and diluted$0.46 $0.17 $1.60 $1.13 
Weighted average limited partners’ units outstanding105,440 105,440 105,440 105,440 

  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 describedNet 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.
Nine Months Ended
September 30,
20212020
Cash flows from operating activities
Net income$176,072 $125,865 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization71,894 75,202 
Gain on sale of assets(5,567)(887)
Loss on early extinguishment of debt— 25,915 
Gain on sales-type leases(24,677)(33,834)
Goodwill impairment11,034 35,653 
Amortization of deferred charges2,992 2,479 
Equity-based compensation expense1,856 1,547 
Equity in earnings of equity method investments, net of distributions— (238)
(Increase) decrease in operating assets:
Accounts receivable—trade3,020 4,874 
Accounts receivable—affiliates6,465 3,212 
Prepaid and other current assets2,452 1,885 
Increase (decrease) in operating liabilities:
Accounts payable—trade3,202 (2,258)
Accounts payable—affiliates(3,515)(9,815)
Accrued interest(6,288)(8,515)
Deferred revenue(3,702)(3,675)
Accrued property taxes4,885 5,173 
Other current liabilities183 544 
Other, net468 1,913 
Net cash provided by operating activities240,774 225,040 
Cash flows from investing activities
Additions to properties and equipment(78,592)(38,642)
Investment in Cushing Connect JV Terminal— (2,438)
Proceeds from sale of assets7,365 961 
Distributions in excess of equity in earnings of equity investments3,517 701 
Net cash used for investing activities(67,710)(39,418)
Cash flows from financing activities
Borrowings under credit agreement210,500 219,500 
Repayments of credit agreement borrowings(283,500)(237,000)
Redemption of senior notes— (522,500)
Proceeds from issuance of debt— 500,000 
Contributions from general partner— 611 
Contributions from noncontrolling interests21,285 15,382 
Distributions to HEP unitholders(112,384)(137,437)
Distributions to noncontrolling interests(8,743)(7,845)
Payments on finance leases(2,666)(2,666)
Deferred financing costs(6,661)(8,714)
Units withheld for tax withholding obligations(69)(149)
Net cash used by financing activities(182,238)(180,818)
Cash and cash equivalents
Increase (decrease) for the period(9,174)4,804 
Beginning of period21,990 13,287 
End of period$12,816 $18,091 
Supplemental disclosure of cash flow information
Cash paid during the period for interest$44,147$51,375
See accompanying notes.
- 7 -
Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTSTATEMENTS OF EQUITY
(Unaudited)
(In thousands)
 
Common
Units		Noncontrolling InterestsTotal 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 compensation683 — 683 
Class B unit accretion(893)— (893)
   Other(68)— (68)
Net income65,290 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 compensation527 — 527 
Class B unit accretion(894)— (894)
   Other(2)— (2)
Net income56,639 1,192 57,831 
Balance June 30, 2021$425,218 $142,559 $567,777 
Contributions from noncontrolling interest— 2,358 2,358 
Distributions to HEP unitholders(37,028)— (37,028)
Distributions to noncontrolling interest— (2,871)(2,871)
Equity-based compensation646 — 646 
Class B unit accretion(956)— (956)
Other1 — 1 
Net income50,117 1,187 51,304 
Balance September 30, 2021$437,998 $143,233 $581,231 

- 8 -
Table of 19,
  
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 InterestsTotal 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 compensation506 — 506 
Class B unit accretion(835)— (835)
Other208 — 208 
Net income25,696 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 compensation474 — 474 
Class B unit accretion(835)— (835)
Other80 — 80 
Net income77,305 649 77,954 
Balance June 30, 2020$380,723 $117,783 $498,506 
Contributions from noncontrolling interest— 2,119 2,119 
Distributions to HEP unitholders(34,458)— (34,458)
Distributions to noncontrolling interest— (3,845)(3,845)
Equity-based compensation567 — 567 
Class B unit accretion(894)— (894)
Other177 — 177 
Net income18,706 2,293 20,999 
Balance September 30, 2020$364,821 $118,350 $483,171 


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) bypartnership. As of September 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 ownedown 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 SLCCushing 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 two2 reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note 13.16.


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 subject to amortization and is tested annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a business between entities under common controlreporting unit below its carrying amount. Our goodwill impairment testing first entails either a quantitative assessment or an optional qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If we determine that based on the qualitative factors that it is more likely than not that the carrying amount of the reporting unit is greater than its fair value, a quantitative test is performed in which we estimate the fair value of the related reporting unit. If the carrying amount of a reporting unit exceeds its fair value, the goodwill of that reporting unit is impaired, and we measure goodwill impairment as the excess of the carrying amount of the reporting unit over the related fair value.

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 6 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 performed our annual goodwill impairment testing qualitatively as of July 1, 2021, and determined it was not more likely than not that the carrying amount of each reporting unit was greater than its fair value. Therefore, a quantitative test was not necessary, and no additional impairment of goodwill was recorded.

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 accounted forrecorded 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 thoughproducts 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 transfer occurred asdefinition of a lease since (1) performance of the beginningcontracts 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 adjustedoutput associated with the specified property, plant, or equipment. Prior to include the historical results and assetsadoption of the acquisitionsnew 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 HFClease components under certain conditions. The majority of our contracts meet these conditions, and we have made this election for all periods presentedthose 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.
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The majority of our long-term transportation contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of shipments in the event a customer ships below their contractual requirements. If there are no future performance obligations, we will recognize these deficiency payments in revenue.
In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize 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 nine months ended September 30, 2021 and 2020, we recognized $12.3 million and $13.8 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 datesJanuary 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 referuse 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 lease payments over a similar term in a similar economic environment. We use the implicit rate when readily determinable.

Operating leases are recorded in operating lease right-of-use assets and current and noncurrent operating lease liabilities on our 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 option. Leases with a term of 12 months or less are not recorded on our balance sheet, and lease expense is accounted for on a straight-line basis. In addition, as a lessee, we separate non-lease components that are identifiable and 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 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 a material impact on our financial condition, results of the acquisitions prior to their respective acquisition dates as those of our "Predecessor." Many of these transactions areoperations or 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.flows.





Acquisitions

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OsageNote 2:Sinclair Acquisition

HEP Transactions

On February 22, 2016, HFC obtainedAugust 2, 2021, HEP, The Sinclair Companies (“Sinclair”) and Sinclair Transportation Company, a 50% membership interest in Osage in a non-monetary exchange for a 20-year terminalling services agreement, whereby awholly owned subsidiary of Magellan Midstream PartnersSinclair (“Magellan”STC”) will provide terminalling services for all HFC products originating in Artesia, New Mexico requiring terminalling in or through El Paso, Texas. Osage is the owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also connects to the Jayhawk pipeline serving the CHS Inc. refinery in McPherson, Kansas. The Osage Pipeline is the primary pipeline supplying HFC’s El Dorado refinery with crude oil.

Concurrent with this transaction, we, entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in OsageContribution Agreement (the “Contribution Agreement”) pursuant to which HEP will acquire all of the outstanding shares of STC in exchange for our El Paso terminal. Under this exchange, we agreed21 million newly issued common units of HEP and cash consideration equal to build two connections on our south products pipeline system$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 permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange, we became thebe named operator of the Osage Pipeline and transitioned into that role on September 1, 2016. Since we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis of its 50% membership interest in Osage of $44.5 million offset by our net carrying basis in the El Paso terminal of $12.1 million with the difference recorded as a contribution from HFC. However, since these transactions were concurrent, there was no impact on periods prior to February 22, 2016.

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

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

Cheyenne Pipeline
On June 3, 2016, we acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne Pipeline,“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 contributioncondition to obtaining antitrust clearance for the Sinclair Transactions, HEP agrees to divest a portion of $42.6 millionits equity interest in cash to Cheyenne Pipeline LLC. CheyenneUNEV 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 (the “HSR Act”), and the consummation of the HFC Transactions. On August 23, 2021, each of HollyFrontier and Sinclair filed its respective premerger notification and report regarding the Sinclair Transactions with the U.S. Department of Justice and the U.S. Federal Trade Commission (the “FTC”) under the HSR Act. On September 22, 2021, HFC and Sinclair each received a request for additional information and documentary material (“Second Request”) from the FTC in connection with the FTC’s review of the Sinclair Transactions. Issuance of the Second Request extends the waiting period under the HSR Act until 30 days after both HollyFrontier and Sinclair have substantially complied with the Second Request, unless the waiting period is terminated earlier by the FTC or the parties otherwise commit not to close the Sinclair Transactions for some additional period of time. HollyFrontier and Sinclair are cooperating with the FTC staff in its review.

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 operated by an affiliategranted the right to nominate 1 director to the HEP board of Plains, which ownsdirectors at the remaining 50% interest.closing. The 87-mile crude oil pipeline runs from Fort LaramieSinclair stockholders have also agreed to Cheyenne, Wyomingcertain customary lock-up restrictions and has an 80,000 barrel per day (“bpd”) capacity.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.


Woods Cross OperatingSee Note 11 for a description of the Letter Agreement between HFC and HEP entered into in connection with the Contribution Agreement.
Effective
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Note 3:Investment in Joint Venture

On October 1, 2016, we acquired all the membership interests of Woods Cross Operating2, 2019, HEP Cushing LLC (“Woods Cross Operating”HEP Cushing”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit,HEP, 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 LLCPlains Marketing, L.P. (“HFC Woods Cross Refining”PMLP”) 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 werewholly 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.

  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


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 and the remaining 50% interest in Frontier Aspen from subsidiariessubsidiary 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. Asa 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 was placed into service at the end of 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 interestsThe Cushing Connect Joint Venture contracted with an affiliate of 25%HEP to manage the construction and operation of SLCthe Cushing Connect Pipeline and 50%with an affiliate of Frontier Aspen. As a resultPlains to manage the operation of the acquisitions, SLCCushing 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 AspenCushing Connect Pipeline construction costs will be approximately $70 million to $75 million.

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

This acquisition will accountedthe 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 achievedgroup, 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 allocatedCushing 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 valueextent 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 4:Revenues

Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. See Note 1 for further discussion of revenue recognition.

Disaggregated revenues were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In thousands)(In thousands)
Pipelines$67,354 $68,292 $202,180 $197,718 
Terminals, tanks and loading racks33,317 39,036 108,386 112,814 
Refinery processing units21,913 20,403 65,436 59,860 
$122,584 $127,731 $376,002 $370,392 

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Revenues on our consolidated statements of income were composed of the following lease and service revenues:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In thousands)(In thousands)
Lease revenues$84,074 $90,077 $258,877 $269,931 
Service revenues38,510 37,654 117,125 100,461 
$122,584 $127,731 $376,002 $370,392 
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. 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.table below:

September 30,
2021		December 31,
2020
 (In thousands)
Contract assets$6,593 $6,306 
Contract liabilities$(482)$(500)
SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal of the Frontier Pipeline
The contract assets and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah that supplies Canadianliabilities include both lease and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.

Accounting Pronouncements Adoptedservice components. During the Periods Presented

Earnings Per Unit
In April 2015, an accounting standard update was issued requiring changes to the allocation of the earnings or losses of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating historical earnings per unit. We adopted this standard as of January 1, 2016. In connection with the dropdown of assets from HFC’s Tulsa refinery on March 31, 2016, and the purchase of HFC’s Woods Cross refinery units on October 1, 2016, we reduced net income by $7.5 million and $10.7 million for the three and nine months ended September 30, 2016.2021, we recognized $0.5 million of revenue that was previously included in contract liability as of December 31, 2020. During the nine months ended September 30, 2021, we also recognized $0.3 million of revenue included in contract assets.

As of September 30, 2021, we expect to recognize $1.7 billion in revenue related to our unfulfilled performance obligations under the terms of our long-term throughput agreements and leases expiring in 2022 through 2036. 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 accountingagreements generally provide for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classificationchanges in the statementminimum revenue guarantees annually for increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index, with certain contracts having provisions that limit the level of cash flows. the rate increases or decreases. We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and lease revenues):
Years Ending December 31,(In millions)
Remainder of 2021$84 
2022312 
2023276 
2024238 
2025172 
2026157 
Thereafter483 
Total$1,722 
Payment terms under our contracts with customers are consistent with industry norms and are typically payable within 10 to 30 days of the date of invoice.

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Note 5:Leases

We adopted this standardASC 842 effective January 1, 2017, with no impact2019, 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
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 guidanceadopt using the modified retrospective implementationtransition method wherebyand practical expedients, both of which are provided as options by the standard and further defined in Note 1. See Note 1 for further discussion of lease accounting.

Lessee Accounting
As a cumulative effect adjustment is recordedlessee, we lease land, buildings, pipelines, transportation and other equipment to retained earningssupport our operations. These leases can be categorized into operating and finance leases.

Our leases have remaining terms of less than 1 year to 23 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 September 30, 2021 and December 31, 2020, respectively, with accumulated depreciation of $3.4 million as of both September 30, 2021 and December 31, 2020. 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):
September 30,
2021		December 31, 2020
Operating leases:
   Operating lease right-of-use assets, net$2,501 $2,979 
   Current operating lease liabilities706 875 
   Noncurrent operating lease liabilities2,169 2,476 
      Total operating lease liabilities$2,875 $3,351 
Finance leases:
   Properties and equipment$6,031 $6,410 
   Accumulated amortization(3,437)(3,390)
      Properties and equipment, net$2,594 $3,020 
   Current finance lease liabilities$3,753 $3,713 
   Noncurrent finance lease liabilities65,565 68,047 
      Total finance lease liabilities$69,318 $71,760 
Weighted average remaining lease term (in years):
   Operating leases5.85.9
   Finance leases15.215.9
Weighted average discount rate:
   Operating leases4.8%4.8%
   Finance leases5.6%5.6%

- 16 -


Supplemental cash flow and other information related to leases were as follows:
Nine Months Ended
September 30,
20212020
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows on operating leases$855 $773 
Operating cash flows on finance leases$3,110 $3,241 
Financing cash flows on finance leases$2,666 $2,666 
Maturities of lease liabilities were as follows:
September 30, 2021
OperatingFinance
(In thousands)
2021$262 $1,832 
2022690 7,335 
2023603 7,374 
2024497 6,929 
2025429 6,470 
2026 and thereafter787 73,888 
   Total lease payments3,268 103,828 
Less: Imputed interest(393)(34,510)
   Total lease obligations2,875 69,318 
Less: Current lease liabilities(706)(3,753)
   Noncurrent lease liabilities$2,169 $65,565 

The components of lease expense were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In thousands)
Operating lease costs$260 $242 $807 $745 
Finance lease costs
   Amortization of assets195 251 607 766 
   Interest on lease liabilities983 1,032 2,983 3,108 
Variable lease cost43 64 175 159 
Total net lease cost$1,481 $1,589 $4,572 $4,778 

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 obligationsmajority 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 oncustomers meet the definition of a businesslease.

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 nine months ended September 30, 2021, we entered into new agreements, and amended other agreements, with HFC related to our Cheyenne assets, Tulsa West lube racks, various crude tanks and new Navajo tanks, and the agreements we previously entered into relating to the Cushing Connect Pipeline became effective. These agreements met the criteria of sales-
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type leases since the underlying assets are not expected to have an alternative use at the end of the lease terms to anyone other than HFC. Under sales-type lease accounting, at the commencement date, the lessor recognizes a net investment in relationthe 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 nine months ended September 30, 2021 composed of the following:
Nine Months Ended September 30, 2021
(In thousands)
Net investment in leases$143,720 
Properties and equipment, net(125,602)
Deferred revenue6,559 
Gain on sales-type leases$24,677 

During the nine months ended September 30, 2020, one of our throughput agreements with Delek US Holdings, Inc. (“Delek”) was partially renewed. A component of this agreement met the criteria of a sales-type lease 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 intangibleat 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 effectiveat 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 nine months ended September 30, 2020 composed of the following:
Nine Months Ended September 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
September 30,		Nine Months Ended
September 30,
2021202020212020
(In thousands)
Operating lease revenues$80,907 $87,125 $251,605 $262,518 
Direct financing lease interest income521 525 1,568 1,572 
Gain on sales-type leases— — 24,677 33,834 
Sales-type lease interest income6,313 2,278 18,429 6,218 
Lease revenues relating to variable lease payments not included in measurement of the sales-type lease receivable3,167 2,952 7,272 7,413 
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 inrecorded 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 recognizedremaining 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 assetpayments, and these variable lease payments were recorded in lease revenues.

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Annual minimum undiscounted lease payments under our leases were as follows as of September 30, 2021:
OperatingFinanceSales-type
Years Ending December 31,(In thousands)
Remainder of 2021$71,001 $544 $10,525 
2022283,916 2,171 42,102 
2023253,459 2,175 38,196 
2024217,355 2,192 34,967 
2025153,934 2,209 31,539 
2026 and thereafter558,415 38,837 279,406 
Total lease receipt payments$1,538,080 $48,128 $436,735 
Less: Imputed interest(31,734)(367,089)
16,394 69,646 
Unguaranteed residual assets at end of leases— 224,779 
Net investment in leases$16,394 $294,425 

Net investments in leases recorded on our balance sheet were composed of the following:
September 30, 2021December 31, 2020
Sales-type LeasesDirect Financing LeasesSales-type LeasesDirect Financing Leases
(In thousands)(In thousands)
Lease receivables (1)
$211,053 $16,394 $88,922 $16,452 
Unguaranteed residual assets83,372 — 64,551 — 
Net investment in leases$294,425 $16,394 $153,473 $16,452 

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


Note 6: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:
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(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:
 September 30, 2021December 31, 2020
Financial InstrumentFair Value Input LevelCarrying
Value		Fair ValueCarrying
Value		Fair Value
(In thousands)
Liabilities:
5% Senior NotesLevel 2492,809 506,770 492,103 506,540 
    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 10 for additional information.

Non-Recurring Fair Value Measurements
For gains on sales-type leases recognized during the nine months ended September 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.

At March 31, 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 ismeasurements were based on the net present valuea combination of expected futurevaluation methods including discounted cash flows, related to both variablethe guideline public company and fixed-rate legsguideline 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.7:Properties and Equipment



Note 3:
Properties and Equipment


The carrying amounts of our properties and equipment arewere as follows:
September 30,
2021		December 31,
2020
 (In thousands)
Pipelines, terminals and tankage(1)
$1,545,545 $1,575,815 
Refinery assets348,882 348,882 
Land and right of way86,781 87,076 
Construction in progress14,878 58,467 
Other(1)
43,876 46,201 
2,039,962 2,116,441 
Less accumulated depreciation(704,920)(665,756)
$1,335,042 $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
Depreciation expense was $60.9 million and $0.2$64.3 million during the three months ended September 30, 2017 and 2016, respectively and $0.7 million and $0.5 million duringfor the nine months ended September 30, 20172021 and 2016, respectively, in interest attributable to construction projects.

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




Note 4:Transportation Agreements

OurNote 8:Intangible Assets

Intangible assets include transportation agreements are intangible assetsand customer relationships that represent a portion of the total purchase price of certain assets acquired from AlonDelek 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.


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The carrying amounts of our transportation agreements areintangible assets were as follows:
Useful LifeSeptember 30,
2021		December 31,
2020
 (In thousands)
Delek transportation agreement30 years$59,933 $59,933 
HFC transportation agreement10-15 years75,131 75,131 
Customer relationships10 years69,683 69,683 
Other20 years50 50 
204,797 204,797 
Less accumulated amortization(127,988)(117,482)
$76,809 $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$10.5 million for each ofboth the nine months ended September 30, 20172021 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 VIEvariable interest entity of HFC; therefore, our basis in these agreements is zero0 and does not reflect a step-up in basis to fair value.





Note 5:Employees, Retirement and Incentive Plans

Note 9: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$2.1 million and $1.4$1.9 million for the three months ended September 30, 20172021 and 2016,2020, respectively, and $4.5$6.2 million and $4.3$5.7 million for the nine months ended September 30, 20172021 and 2016.2020, respectively.


Under HLS’s secondment agreement with HFC (the “Secondment Agreement”), certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs related to these employees.
We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four5 components: restricted or phantom units, performance units, unit options, and unit appreciation rights.rights and cash awards. 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 30, 2017,2021, we had two2 types of incentive-based awards outstanding, which are described below. The compensation cost charged against income was $0.7$0.6 million for each ofboth the three months ended September 30, 20172021 and 2016,2020, and $1.6$1.9 million and $1.9$1.5 million for the nine months ended September 30, 20172021 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 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 been860,361 were available to be granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.


RestrictedPhantom Units
Under our Long-Term Incentive Plan, we grant restrictedphantom 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 restrictedphantom 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.


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A summary of restrictedphantom unit activity and changes during the nine months ended September 30, 2017,2021, is presented below:
Phantom UnitsUnitsWeighted Average Grant-Date Fair Value
Outstanding at January 1, 2021 (nonvested)295,992 $14.48 
Vesting and transfer of full ownership to recipients(823)16.24 
Forfeited(6,833)15.54 
Outstanding at September 30, 2021 (nonvested)288,336 14.45 
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 nine months ended September 30, 2021 and 2020 were $13 thousand and $0.2 million, respectively. As of September 30, 2017, there was $1.12021, $1.4 million of total unrecognized compensation expense related to nonvested restrictedunvested phantom unit grants which is expected to be recognized over a weighted-average period of 0.9 year.1.2 years.


Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executivesofficers 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. Asperiod 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 targettotal 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 months ended September 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 commontarget 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 duringfor the nine months ended September 30, 2017,2021, is presented below:
Performance UnitsUnits
Outstanding at January 1, 20172021 (nonvested)49,52077,472 
Vesting and transfer of common units to recipients(2,262(10,881))
Forfeited(21,228)
Outstanding at September 30, 20172021 (nonvested)26,03066,591 


The grant-dategrant date fair value of performance units vested and transferred to recipients during both of the nine months ended September 30, 2017,2021 and 2020 was $0.1$0.4 million. Based on the weighted averageweighted-average fair value of performance units outstanding at September 30, 2017,2021, of $0.9$1.2 million, there was $0.5$0.4 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.81.5 years.



During the nine months ended September 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


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Note 10:Debt

Credit Agreement
We have a $1.4 billionIn April 2021, we amended our senior secured revolving credit facility (the “Credit Agreement”) expiring indecreasing 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 containscontinues to provide for an accordion feature givingthat allows us the ability to increase commitments under the size of the facility byCredit Agreement up to $300 million with additional lender commitments.a maximum amount of $1.7 billion.


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-ownedwholly 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 expirationmaturity 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 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 20242028 (the “ 6%"5% Senior Notes”Notes"). On September 22, 2017,February 5, 2020, we closed a private placement of an additional $100redeemed the existing $500 million in aggregate offering of the 6% Senior Notes forat a combined aggregate principal amount outstandingredemption 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 30, 2017.2021. At any time when the 6%5% Senior Notes are rated investment grade by botheither Moody’s andor 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 wholly-owned subsidiaries.existing wholly owned 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:
September 30,
2021		December 31,
2020
(In thousands)
Credit Agreement
Amount outstanding$840,500 913,500 
5% Senior Notes
Principal500,000 500,000 
Unamortized premium and debt issuance costs(7,191)(7,897)
492,809 492,103 
Total long-term debt$1,333,309 $1,405,603 


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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 11: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 20192022 to 2036.2036, and revenues from HFC accounted for 79% of our total revenues for both the three and nine months ended September 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 30, 2017,2021, these agreements with HFC require minimum annualized payments to us of $321.3$353 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 arewere as follows:
•Revenues received from HFC were $95.1$97.1 million and $77.4$101.0 million for the three months ended September 30, 20172021 and 2016,2020, respectively, and $277.3$298.2 million and $239.4$298.0 million for the nine months ended September 30, 20172021 and 2016,2020, respectively.
•HFC charged us general and administrative services under the Omnibus Agreement of $0.6$0.7 million for each ofboth the three months ended September 30, 20172021 and 2016,2020, and $1.8$2.0 million for each ofboth the nine months ended September 30, 20172021 and 2016.2020.
•We reimbursed HFC for costs of employees supporting our operations of $11.7$15.6 million and $10.0$14.0 million for the three months ended September 30, 20172021 and 2016,2020, respectively, and $34.5$44.2 million and $29.4$41.3 million for the nine months ended September 30, 20172021 and 2016,2020, respectively.
•HFC reimbursed us $1.9$1.8 million and $4.5$2.3 million for the three months ended September 30, 20172021 and 2016,2020, respectively, and $4.7$6.1 million and $11.2$6.3 million for the nine months ended September 30, 20172021 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 30, 20172021 and 2016,2020, respectively, and $94.8$62.6 million and $76.0$74.3 million forin the nine months ended September 30, 20172021 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$41.5 million and $42.6$48.0 million at September 30, 2017,2021, and December 31, 2016,2020, respectively.
•Accounts payable to HFC were $9.6$14.6 million and $16.4$18.1 million at September 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 included $0.4 million for both September 30, 20172021 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 anyuse of our Artesia and Tulsa rail yards of $0.5 million for both of the $5.8 million deferred atthree months ended September 30, 2017.2021 and 2020, respectively, and $1.6 million for the nine months ended September 30, 2021 and $1.5 million for the nine months ended September 30, 2020.
•We recorded a gain on sales-type leases with HFC of $24.7 million for the nine months ended September 30, 2021, and we received sales-type lease payments of $6.6 million and $2.4 million from HFC for the three months ended September 30, 2021 and 2020, respectively, and $19.1 million and $7.1 million for the nine months ended September 30, 2021 and 2020, respectively.
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•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 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.


Note 9:Partners’ Equity

On August 2, 2021, in connection with the Sinclair Transactions (described in Note 2 above), 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 2 above).

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, 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 12: Partners’ Equity, Income Allocations and Cash Distributions

As of September 30, 2017,2021, HFC held 22,380,03059,630,030 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 endedAs of September 30, 2017,2021, HEP has issued 1,538,4522,413,153 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, 2017,21, 2021, we announced our cash distribution for the third quarter of 20172021 of $0.6450$0.35 per unit. The distribution is payable on all common units and will be paid November 14, 2017,12, 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 1.1, 2021.


The following table presents the allocation of ourOur regular quarterly cash distributionsdistribution to the general and limited partners will be $37.0 million for the periods in which they apply.three months ended September 30, 2021 and was $37.0 million for the three months ended September 30, 2020. For the nine months ended September 30, 2021, the regular quarterly distribution to the limited partners will be $111.1 million and was $105.9 million for the nine months ended September 30, 2020. Our distributions are declared subsequent to quarter end; therefore, thethese 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:Net Income Per Limited Partner Unit

Note 13: Net Income Per Limited Partner Unit
Net
Basic net income per unit applicable to the limited partners is computed usingcalculated as net income attributable to the two-class method because we have more than one classpartners 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 commonthe net incremental units general partnerfrom 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
- 25 -

percentage during the period, after consideration of any priority allocations of earnings. TheOur 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.

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, netNet income per limited partner unit is computed as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In thousands, except per unit data)
Net income attributable to the partners$49,160 $17,813 $169,302 $119,144 
Less: Participating securities’ share in earnings(165)— (579)— 
Net income attributable to common units48,995 17,813 168,723 119,144 
Weighted average limited partners' units outstanding105,440 105,440 105,440 105,440 
Limited partners' per unit interest in earnings - basic and diluted$0.46 $0.17 $1.60 $1.13 


Note 14: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 for environmental remediation obligationsexpensed $0.7 million and $1.3 million for the three and nine months ended September 30, 2017, as well as2021, respectively, for environmental remediation obligations, and we expensed $1.0 million and $1.6 million for the three months ended September 30, 2016. For theand 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$4.6 million and $7.1$4.5 million at September 30, 2017,2021 and December 31, 2016, respectively,2020, of which $4.7$2.5 million and $5.4 million, respectively, werewas classified as other long-term liabilities.liabilities for both periods. 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, ourOur 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 September 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 15: 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 16: Segment Information

Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in two2 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 pipelinesPipelines and terminals segment hashave 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 operatingreportable 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
September 30,		Nine Months Ended
September 30,
 2017 2016 2017 20162021202020212020
      (In thousands)
Revenues:        Revenues:
Pipelines and terminals - affiliate $74,547
 $73,210
 $219,806
 $226,553
Pipelines and terminals - affiliate$75,211 $80,589 $232,756 $238,123 
Pipelines and terminals - third-party 15,226
 15,212
 47,826
 50,094
Pipelines and terminals - third-party25,460 26,739 77,810 72,409 
Refinery processing units - affiliate 20,591
 4,188
 57,510
 12,870
Refinery processing units - affiliate21,913 20,403 65,436 59,860 
Total segment revenues $110,364
 $92,610
 $325,142
 $289,517
Total segment revenues$122,584 $127,731 $376,002 $370,392 
        
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)
$48,268 $15,912 $139,143 $120,445 
Refinery processing units 10,463
 (7,339) 24,283
 (6,491)Refinery processing units9,697 9,973 27,705 29,371 
Total segment operating income 55,359
 41,589
 164,829
 149,166
Total segment operating income57,965 25,885 166,848 149,816 
Unallocated general and administrative expenses (3,623) (2,664) (8,872) (8,618)Unallocated general and administrative expenses(3,849)(2,332)(9,664)(7,569)
Interest and financing costs, net (13,971) (14,339) (53,278) (35,926)Interest and financing costs, net(6,582)(11,301)(20,598)(37,816)
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 debtLoss on early extinguishment of debt— — — (25,915)
Equity in earnings of equity method investmentsEquity in earnings of equity method investments3,689 1,316 8,875 5,186 
Gain on sales-type leasesGain on sales-type leases— — 24,677 33,834 
Gain (loss) on sale of assets and otherGain (loss) on sale of assets and other77 7,465 5,994 8,439 
Income before income taxes $42,992
 $28,465
 $113,961
 $114,881
Income before income taxes$51,300 $21,033 $176,132 $125,975 
        
Capital Expenditures:        Capital Expenditures:
Pipelines and terminals $10,151
 $15,557
 $30,437
 $47,200
 Pipelines and terminals$19,049 $7,902 $77,826 $38,318 
Refinery processing units —
 5,173
 238
 48,915
 Refinery processing units168 — 766 324 
Total capital expenditures $10,151
 $20,730
 $30,675
 $96,115
Total capital expenditures$19,217 $7,902 $78,592 $38,642 


September 30, 2021December 31, 2020
(In thousands)
Identifiable assets:
  Pipelines and terminals (2)
$1,728,983 $1,729,547 
  Refinery processing units291,838 305,090 
Other131,755 132,928 
Total identifiable assets$2,152,576 $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 lossincome included goodwill impairment charges of $11.0 million for the nine months ended September 30, 2021 and $35.7 million for both the three and nine months ended September 30, 2016, is due to the net loss attributable to Predecessor.2020.
(2) Included goodwill of $223.7 million as of September 30, 2021 and $234.7 million as of December 31, 2020.
Note 14:Supplemental Guarantor/Non-Guarantor Financial Information


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Note 17: 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.

- 28 -

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
September 30, 2021ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
ASSETS
Current assets:
Cash and cash equivalents$350 $(346)$12,812 $— $12,816 
Accounts receivable— 47,696 5,968 (36)53,628 
Prepaid and other current assets151 7,447 868 (292)8,174 
Total current assets501 54,797 19,648 (328)74,618 
Properties and equipment, net— 1,030,270 304,772 — 1,335,042 
Operating lease right-of-use assets— 2,397 104 — 2,501 
Net investment in leases— 306,069 95,458 (95,456)306,071 
Investment in subsidiaries
1,774,250 297,809 — (2,072,059)— 
Intangible assets, net— 76,809 — — 76,809 
Goodwill— 223,650 — — 223,650 
Equity method investments— 79,337 37,690 — 117,027 
Other assets8,643 8,215 — — 16,858 
Total assets$1,783,394 $2,079,353 $457,672 $(2,167,843)$2,152,576 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$— $28,150 $11,963 $(36)$40,077 
Accrued interest4,604 — — — 4,604 
Deferred revenue— 10,287 481 — 10,768 
Accrued property taxes— 5,576 3,301 — 8,877 
Current operating lease liabilities— 632 74 — 706 
Current finance lease liabilities— 5,533 — (1,780)3,753 
Other current liabilities— 2,302 385 — 2,687 
Total current liabilities4,604 52,480 16,204 (1,816)71,472 
Long-term debt1,333,309 — — — 1,333,309 
Noncurrent operating lease liabilities— 2,169 — — 2,169 
Noncurrent finance lease liabilities— 152,310 — (86,745)65,565 
Other long-term liabilities260 11,631 426 — 12,317 
Deferred revenue— 30,920 — — 30,920 
Class B unit— 55,593 — — 55,593 
Equity - partners445,221 1,774,250 297,809 (2,079,282)437,998 
Equity - noncontrolling interests— — 143,233 — 143,233 
Total liabilities and equity$1,783,394 $2,079,353 $457,672 $(2,167,843)$2,152,576 
- 29 -


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, 2020ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
ASSETS
Current assets:
Cash and cash equivalents$1,627 $(987)$21,350 $— $21,990 
Accounts receivable— 56,522 6,308 (315)62,515 
Prepaid and other current assets349 8,366 772 — 9,487 
Total current assets1,976 63,901 28,430 (315)93,992 
Properties and equipment, net— 1,087,184 363,501 — 1,450,685 
Operating lease right-of-use assets— 2,822 157 — 2,979 
Net investment in leases— 166,316 — — 166,316 
Investment in subsidiaries1,789,808 286,883 — (2,076,691)— 
Intangible assets, net— 87,315 — — 87,315 
Goodwill— 234,684 — — 234,684 
Equity method investments— 81,089 39,455 — 120,544 
Other assets4,268 6,782 — — 11,050 
Total assets$1,796,052 $2,016,976 $431,543 $(2,077,006)$2,167,565 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$— $30,252 $16,463 $(315)$46,400 
Accrued interest10,892 — — — 10,892 
Deferred revenue— 10,868 500 — 11,368 
Accrued property taxes— 2,915 1,077 — 3,992 
Current operating lease liabilities— 804 71 — 875 
Current finance lease liabilities— 3,713 — — 3,713 
Other current liabilities5 2,491 9 — 2,505 
Total current liabilities10,897 51,043 18,120 (315)79,745 
Long-term debt1,405,603 — — — 1,405,603 
Noncurrent operating lease liabilities— 2,476 — — 2,476 
Noncurrent finance lease liabilities— 68,047 — — 68,047 
Other long-term liabilities260 12,171 474 — 12,905 
Deferred revenue— 40,581 — — 40,581 
Class B unit— 52,850 — — 52,850 
Equity - partners379,292 1,789,808 286,883 (2,076,691)379,292 
Equity - noncontrolling interests— — 126,066 — 126,066 
Total liabilities and equity$1,796,052 $2,016,976 $431,543 $(2,077,006)$2,167,565 



- 30 -


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 September 30, 2021ParentGuarantor Restricted
Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $90,980 $6,144 $— $97,124 
Third parties— 20,024 5,436 — 25,460 
— 111,004 11,580 — 122,584 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 38,676 4,117 — 42,793 
Depreciation and amortization— 17,558 4,268 — 21,826 
General and administrative739 3,110 — — 3,849 
739 59,344 8,385 — 68,468 
Operating income (loss)(739)51,660 3,195 — 54,116 
Other income (expense):
Equity in earnings of subsidiaries69,553 3,045 — (72,598)— 
Equity in earnings of equity method investments— 2,743 946 — 3,689 
Interest expense(12,431)(1,077)— 91 (13,417)
Interest income— 6,835 91 (91)6,835 
Gain on sales-type lease— 7,223 — (7,223)— 
Gain on sale of assets and other— 76 1 — 77 
57,122 18,845 1,038 (79,821)(2,816)
Income before income taxes56,383 70,505 4,233 (79,821)51,300 
State income tax benefit— 4 — — 4 
Net income56,383 70,509 4,233 (79,821)51,304 
Allocation of net income attributable to noncontrolling interests— (956)(1,188)— (2,144)
Net income attributable to the partners$56,383 $69,553 $3,045 $(79,821)$49,160 

- 31 -


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 September 30, 2020ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $94,595 $6,397 $— $100,992 
Third parties— 21,550 5,189 — 26,739 
— 116,145 11,586 — 127,731 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 36,065 3,938 — 40,003 
Depreciation and amortization— 21,997 4,193 — 26,190 
General and administrative649 1,683 — — 2,332 
Goodwill impairment— 35,653 — — 35,653 
649 95,398 8,131 — 104,178 
Operating income (loss)(649)20,747 3,455 — 23,553 
Other income (expense):
Equity in earnings of subsidiaries31,461 6,589 — (38,050)— 
Equity in earnings of equity method investments— 755 561 — 1,316 
Interest expense(13,072)(1,032)— — (14,104)
Interest income— 2,787 16 — 2,803 
Gain on sale of assets and other73 2,542 4,850 — 7,465 
18,462 11,641 5,427 (38,050)(2,520)
Income before income taxes17,813 32,388 8,882 (38,050)21,033 
State income tax expense— (34)— — (34)
Net income17,813 32,354 8,882 (38,050)20,999 
Allocation of net income attributable to noncontrolling interests— (893)(2,293)— (3,186)
Net income attributable to the partners$17,813 $31,461 $6,589 $(38,050)$17,813 

- 32 -


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
Nine Months Ended September 30, 2021ParentGuarantor Restricted
Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $279,592 $18,600 $— $298,192 
Third parties— 59,554 18,256 — 77,810 
— 339,146 36,856 — 376,002 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 114,217 12,009 — 126,226 
Depreciation and amortization— 59,045 12,849 — 71,894 
General and administrative2,824 6,840 — — 9,664 
Goodwill impairment— 11,034 — — 11,034 
2,824 191,136 24,858 — 218,818 
Operating income (loss)(2,824)148,010 11,998 — 157,184 
Other income (expense):
Equity in earnings of subsidiaries216,958 10,786 — (227,744)— 
Equity in earnings of equity method investments— 6,154 2,721 — 8,875 
Interest expense(37,609)(3,077)— 91 (40,595)
Interest income— 19,997 91 (91)19,997 
Gain on sales-type lease— 31,900 — (7,223)24,677 
Gain on sale of assets and other— 5,991 3 — 5,994 
179,349 71,751 2,815 (234,967)18,948 
Income before income taxes176,525 219,761 14,813 (234,967)176,132 
State income tax expense— (60)— — (60)
Net income176,525 219,701 14,813 (234,967)176,072 
Allocation of net income attributable to noncontrolling interests— (2,743)(4,027)— (6,770)
Net income attributable to the partners$176,525 $216,958 $10,786 $(234,967)$169,302 

- 33 -


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 FlowsIncome
Nine Months Ended September 30, 2020ParentGuarantor Restricted
Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $278,767 $19,216 $— $297,983 
Third parties— 56,592 15,817 — 72,409 
— 335,359 35,033 — 370,392 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 98,176 11,545 — 109,721 
Depreciation and amortization— 62,489 12,713 — 75,202 
General and administrative2,528 5,041 — — 7,569 
Goodwill impairment— 35,653 — — 35,653 
2,528 201,359 24,258 — 228,145 
Operating income (loss)(2,528)134,000 10,775 — 142,247 
Other income (expense):
Equity in earnings of subsidiaries189,889 12,394 — (202,283)— 
Equity in earnings of equity method investments— 4,292 894 — 5,186 
Interest expense(42,542)(3,108)— — (45,650)
Interest income26 7,792 16 — 7,834 
Loss on early extinguishment of debt(25,915)— — — (25,915)
Gain on sales-type lease— 33,834 — — 33,834 
Gain on sale of assets and other214 3,358 4,867 — 8,439 
121,672 58,562 5,777 (202,283)(16,272)
Income before income taxes119,144 192,562 16,552 (202,283)125,975 
State income tax expense— (110)— — (110)
Net income119,144 192,452 16,552 (202,283)125,865 
Allocation of net income attributable to noncontrolling interests— (2,563)(4,158)— (6,721)
Net income attributable to the partners$119,144 $189,889 $12,394 $(202,283)$119,144 


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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



Condensed Consolidating Statement of Cash Flows
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.

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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 andand/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, including57% of our outstanding common units and the 2%non-economic general partnership interest as of September 30, 2017.2021.

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 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 willshould support volumes in our product pipelines, crude gathering systemsystems and terminals.
Acquisitions
On February 22, 2016, HFC obtainedAugust 2, 2021, HEP, The Sinclair Companies (“Sinclair”), and Sinclair Transportation Company, a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in a non-monetary exchange for a 20-year terminalling services agreement, whereby awholly owned subsidiary of Magellan Midstream PartnersSinclair (“Magellan”STC”) 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 OsageContribution Agreement (the “Contribution Agreement”) pursuant to which HEP will acquire all of the outstanding shares of STC in exchange for our El Paso terminal. Under this exchange, we also agreed21 million newly issued common units of HEP and cash consideration equal to build two connections$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 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 (the “HSR Act”). On August 23, 2021, each of HollyFrontier and Sinclair filed its respective premerger notification and report regarding the Sinclair Transactions with the U.S. Department of Justice and the U.S. Federal Trade Commission (the “FTC”) under the HSR Act. On September 22, 2021, HFC and Sinclair each received a request for additional information and documentary material (“Second Request”) from the FTC in connection with the FTC’s review of the Sinclair Transactions. Issuance of the Second Request extends the waiting period under the HSR Act until 30 days after both HollyFrontier and Sinclair have substantially complied with the Second Request, unless the waiting period is terminated earlier by the FTC or the parties otherwise commit not to close the Sinclair Transactions for some additional period of time. HollyFrontier and Sinclair are cooperating with the FTC staff in its review. In addition, the HEP Transactions are conditioned on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange,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 the HEP Transactions, the “Sinclair Transactions”). See Note 2 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 becametransport, terminal and store in the named operatormarkets we serve. The impact of the Osage PipelineCOVID-19 pandemic on the global macroeconomy created diminished demand, as well as lack of forward visibility, for refined products and transitioned into that role.

On March 31, 2016, we acquired crude oil tanks locatedtransportation, and for the terminalling and storage services that we provide. Since the declines in demand at HFC’s Tulsa refinery from an affiliatethe beginning of Plains All American Pipeline, L.P. (“Plains”)the COVID-19 pandemic, we began to see improvement in demand for $39.5 million. In 2009, HFC sold these tanks to Plainsproducts and leased them back, and due to HFC’s continuing interestservices beginning late in the tanks, HFC accounted forsecond quarter of 2020 that continued through the transaction as a financing arrangement. Accordingly, the tanks remained on HFC’s balance sheet and were depreciated for accounting purposes. In connectionthird quarter of 2021, 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.

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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 LLCaggregate volumes approaching pre-pandemic levels. We expect our customers will continue to adjust refinery production
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levels commensurate with market demand, and with the increasing availability of vaccines, we believe there is a path to a fulsome recovery in demand.

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.

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 volume commitments, which have expiration dates from 2022 to 2036. These minimum volume commitments accounted for approximately 67% and 76% of our total revenues in the nine months ended September 30, 2021 and the twelve months ended December 31, 2020, respectively. We are currently not aware of any reasons that would prevent such customers from making the minimum payments required under the contracts or potentially making payments in excess of the minimum payments. In addition to these payments, we also expect to collect payments for services provided to uncommitted shippers. There have been no material changes to customer payment terms due to the 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, in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, and in this Form 10-Q. 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 be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramiea significant risk to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.our business.


EffectiveInvestment in Joint Venture
On October 1, 2016, we acquired all the membership interests of Woods Cross Operating2, 2019, HEP Cushing LLC (“Woods Cross Operating”HEP Cushing”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit,HEP, and polymerization unit located at HFC’s Woods Cross Refinery, for cash consideration of $278.0 million. 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 $57.3 million.

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

On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline and the remaining 50% interest in Frontier Aspen from subsidiarieswholly 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, construction, ownership and operation of $250 million. Asa 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, 2017, we held noncontrolling interestsHFC and (ii) the ownership and operation of 25%1.5 million barrels of SLCcrude 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 was placed into service at the end of 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 50%with an affiliate of Frontier Aspen. As a resultPlains to manage the operation of the acquisitions, SLCCushing 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 withconstruction 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 terminalbudget by more than 10%. HEP estimates its share of the Frontiercost 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, Wyomingconstruction 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’sHFC's refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from 20192022 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 30, 2017,2021, these agreements with HFC require minimum annualized payments to us of $321.3$353 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.


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Table of
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.

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.

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.

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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 currentfuture growth plan isplans 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 continueeconomic 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 expectcontinue 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 demonstrated by our pending transaction 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.

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 6 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 performed our annual goodwill impairment testing qualitatively as of July 1, 2021, and determined it was not more likely than not that the carrying amount of each reporting unit was greater than its fair value. Therefore, a quantitative test was not necessary, and no additional impairment of goodwill was recorded.


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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow, Volumes and VolumesBalance Sheet Data
The following tables present income, distributable cash flow and volume information for the three and nine months ended September 30, 20172021 and 2016. These results have been adjusted2020.
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Table of
 Three Months Ended September 30,Change from
 202120202020
 (In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines$18,702 $18,619 $83 
Affiliates—intermediate pipelines7,537 7,537 — 
Affiliates—crude pipelines19,536 20,218 (682)
45,775 46,374 (599)
Third parties—refined product pipelines8,799 9,812 (1,013)
Third parties—crude pipelines12,780 12,106 674 
67,354 68,292 (938)
Terminals, tanks and loading racks:
Affiliates29,436 34,215 (4,779)
Third parties3,881 4,821 (940)
33,317 39,036 (5,719)
Refinery processing units—Affiliates21,913 20,403 1,510 
Total revenues122,584 127,731 (5,147)
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)42,793 40,003 2,790 
Depreciation and amortization21,826 26,190 (4,364)
General and administrative3,849 2,332 1,517 
Goodwill impairment— 35,653 (35,653)
68,468 104,178 (35,710)
Operating income54,116 23,553 30,563 
Other income (expense):
Equity in earnings of equity method investments3,689 1,316 2,373 
Interest expense, including amortization(13,417)(14,104)687 
Interest income6,835 2,803 4,032 
Gain on sale of assets and other77 7,465 (7,388)
(2,816)(2,520)(296)
Income before income taxes51,300 21,033 30,267 
State income tax benefit (expense)4 (34)38 
Net income51,304 20,999 30,305 
Allocation of net income attributable to noncontrolling interests(2,144)(3,186)1,042 
Net income attributable to the partners49,160 17,813 31,347 
Limited partners’ earnings per unit—basic and diluted$0.46 $0.17 $0.29 
Weighted average limited partners’ units outstanding105,440 105,440 — 
EBITDA (1)
$77,564 $55,338 $22,226 
Adjusted EBITDA (1)
$83,270 $86,435 $(3,165)
Distributable cash flow (2)
$66,810 $76,894 $(10,084)
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines115,507 119,403 (3,896)
Affiliates—intermediate pipelines136,398 142,817 (6,419)
Affiliates—crude pipelines271,717 270,840 877 
523,622 533,060 (9,438)
Third parties—refined product pipelines46,834 60,203 (13,369)
Third parties—crude pipelines136,247 133,487 2,760 
706,703 726,750 (20,047)
Terminals and loading racks:
Affiliates419,665 401,904 17,761 
Third parties52,541 57,355 (4,814)
472,206 459,259 12,947 
Refinery processing units—Affiliates72,297 62,016 10,281 
Total for pipelines and terminal and refinery processing unit assets (bpd)1,251,206 1,248,025 3,181 
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Table of
 Nine Months Ended September 30,Change from
 202120202020
 (In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines$56,520 $55,004 $1,516 
Affiliates—intermediate pipelines22,564 22,486 78 
Affiliates—crude pipelines58,241 59,922 (1,681)
137,325 137,412 (87)
Third parties—refined product pipelines28,188 33,360 (5,172)
Third parties—crude pipelines36,667 26,946 9,721 
202,180 197,718 4,462 
Terminals, tanks and loading racks:
Affiliates95,431 100,711 (5,280)
Third parties12,955 12,103 852 
108,386 112,814 (4,428)
Refinery processing units—Affiliates65,436 59,860 5,576 
Total revenues376,002 370,392 5,610 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)126,226 109,721 16,505 
Depreciation and amortization71,894 75,202 (3,308)
General and administrative9,664 7,569 2,095 
Goodwill impairment11,034 35,653 (24,619)
218,818 228,145 (9,327)
Operating income157,184 142,247 14,937 
Other income (expense):
Equity in earnings of equity method investments8,875 5,186 3,689 
Interest expense, including amortization(40,595)(45,650)5,055 
Interest income19,997 7,834 12,163 
Loss on early extinguishment of debt— (25,915)25,915 
Gain on sales-type leases24,677 33,834 (9,157)
Gain on sale of assets and other5,994 8,439 (2,445)
18,948 (16,272)35,220 
Income before income taxes176,132 125,975 50,157 
State income tax expense(60)(110)50 
Net income176,072 125,865 50,207 
Allocation of net income attributable to noncontrolling interests(6,770)(6,721)(49)
Net income attributable to the partners169,302 119,144 50,158 
Limited partners’ earnings per unit—basic and diluted$1.60 $1.13 $0.47 
Weighted average limited partners’ units outstanding105,440 105,440 — 
EBITDA (1)
$261,854 $232,272 $29,582 
Adjusted EBITDA (1)
$259,466 $257,711 $1,755 
Distributable cash flow (2)
$206,707 $213,058 $(6,351)
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines118,033 116,641 1,392 
Affiliates—intermediate pipelines131,873 137,816 (5,943)
Affiliates—crude pipelines261,117 276,128 (15,011)
511,023 530,585 (19,562)
Third parties—refined product pipelines47,805 55,921 (8,116)
Third parties—crude pipelines131,842 103,955 27,887 
690,670 690,461 209 
Terminals and loading racks:
Affiliates386,400 401,245 (14,845)
Third parties50,542 49,753 789 
436,942 450,998 (14,056)
Refinery processing units—Affiliates69,904 60,573 9,331 
Total for pipelines and terminal and refinery processing unit assets (bpd)1,197,516 1,202,032 (4,516)
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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 resultspartners 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) tariffs and fees not included in revenues due to impacts from lease accounting for certain tariffs and fees 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 1minimum guaranteed pipeline and terminal tariffs and fees 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
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  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

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  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 forthremaining amounts recorded as a reduction in the definitive agreement with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HollyFrontier Corporationnet investment in leases. These tariffs 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, HEP issued 37,250,000 of its common units to HEP Logistics. Since this transaction closedfees were previously recorded as revenues prior to the record daterenewal 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 purposescompliance with financial covenants. Set forth below are our calculations of distributions declared, we didEBITDA and Adjusted EBITDA.

 Three Months Ended
September 30,		Nine Months Ended
September 30,
 2021202020212020
 (In thousands)
Net income attributable to the partners$49,160 $17,813 $169,302 $119,144 
Add (subtract):
Interest expense13,417 14,104 40,595 45,650 
Interest income(6,835)(2,803)(19,997)(7,834)
State income tax (benefit) expense(4)34 60 110 
Depreciation and amortization21,826 26,190 71,894 75,202 
EBITDA$77,564 $55,338 $261,854 $232,272 
Loss on early extinguishment of debt— — — 25,915 
Gain on sales-type leases— — (24,677)(33,834)
Gain on significant asset sales— — (5,263)— 
Goodwill impairment— 35,653 11,034 35,653 
HEP's pro-rata share of gain on business interruption insurance settlement— (6,079)— (6,079)
Tariffs and fees not included in revenues7,312 3,129 21,337 8,603 
Lease payments not included in operating costs(1,606)(1,606)(4,819)(4,819)
Adjusted EBITDA$83,270 $86,435 $259,466 $257,711 

(2)Distributable cash flow is not include any incentive or regular distributions ona 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 interestexceptions 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
September 30,		Nine Months Ended
September 30,
 2017 2016 2017 2016 2021202020212020
 (In thousands) (In thousands)
Net income attributable to the partners $42,071
 $34,785
 $108,970
 $116,880
Net income attributable to the partners$49,160 $17,813 $169,302 $119,144 
Add (subtract):        Add (subtract):
Depreciation and amortization 19,007
 18,920
 57,729
 51,183
Depreciation and amortization21,826 26,190 71,894 75,202 
Amortization of discount and deferred debt issuance costs 781
 918
 2,317
 2,294
Amortization of discount and deferred debt issuance costs763 838 2,992 2,479 
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 recognizedCustomer billings greater than revenue recognized(122)(198)(301)(699)
Maintenance capital expenditures (3)
Maintenance capital expenditures (3)
(3,351)(1,565)(8,834)(5,192)
Increase in environmental liabilityIncrease in environmental liability271 29 36 187 
Decrease in reimbursable deferred revenue (917) (750) (2,765) (1,906)Decrease in reimbursable deferred revenue(2,991)(3,257)(10,507)(9,062)
Other non-cash adjustments 592
 788
 2,174
 4,096
Predecessor depreciation and amortization —
 (3,400) —
 (3,521)
Gain on sales-type leasesGain on sales-type leases— — (24,677)(33,834)
Gain on significant asset salesGain on significant asset sales— — (5,263)— 
Goodwill impairmentGoodwill impairment— 35,653 11,034 35,653 
OtherOther1,254 1,391 1,031 3,265 
Distributable cash flow $59,248
 $49,257
 $177,436
 $160,331
Distributable cash flow$66,810 $76,894 $206,707 $213,058 

(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.
September 30,
2021		December 31,
2020
(In thousands)
Balance Sheet Data
Cash and cash equivalents$12,816 $21,990 
Working capital$3,146 $14,247 
Total assets$2,152,576 $2,167,565 
Long-term debt$1,333,309 $1,405,603 
Partners’ equity$437,998 $379,292 


Results of Operations—Three Months Ended September 30, 20172021 Compared with Three Months Ended September 30, 20162020


Summary
Net income attributable to the partners for the third quarter of 2021 was $42.1$49.2 million ($0.660.46 per basic and diluted limited partner unit) compared to $34.8$17.8 million ($0.330.17 per basic and diluted limited partner unit) for the third quarter of 2016.2020. Net income attributable to HEP for the third quarter of 2020 included a goodwill impairment charge of $35.7 million related to our Cheyenne reporting unit and a $6.1 million gain related to HEP's pro-rata share of a business interruption insurance claim settlement resulting from a loss at HollyFrontier's Woods Cross Refinery. Excluding these items, net income attributable to the partners for the third quarters of 2021 and 2020 were $49.2 million ($0.46 per basic and diluted limited partner unit) and $47.4 million ($0.45 per basic and diluted limited partner unit), respectively. The increase in earnings is primarilywas mainly due to increased operatinghigher interest income from our Woods Cross refinery processing units of $8.9 million and increasedassociated with sales-type leases, higher equity in earnings from our equity method investments of $1.3 million.joint ventures and lower depreciation expense partially offset by lower revenues and higher operating expenses.

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.


Revenues
Revenues for the third quarter were $110.4$122.6 million, an increasea decrease of $17.8$5.1 million compared to the third quarter of 2016 primarily2020. The decrease was mainly due to lower on-going revenues on our Cheyenne assets as a result of $16.6 million from the Woods Cross refinery processing units acquired inconversion of the fourth quarter of 2016. Overall pipeline volumes were up 4% compared to the three months ended September 30, 2016, largely due to an increase in both refined product and intermediate pipeline shipments associated with higher production at HFC’s Navajo refinery.HollyFrontier
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Table of Contentsril 19,

Cheyenne Refinery to renewable diesel production, reclassifications of certain tariffs and fees from revenue to interest income under sales-type lease accounting and a 3% decrease in overall crude and product pipeline volumes.


Revenues from our refined product pipelines were $32.2$27.5 million, an increasea decrease of $1.7$0.9 million compared to the third quarter of 2016, and shipments2020. Shipments averaged 217.3 mbpd162.3 thousand barrels per day (“mbpd”) compared to 201.5179.6 mbpd for the third quarter of 2016. Revenues2020. The volume and volumes both increased primarilyrevenue decreases were mainly due to higher shipmentslower volumes on pipelines servicing HollyFrontier's Navajo refinery and our New Mexico refined product pipelines in line with increased production at HFC's Navajoservicing Delek's Big Spring refinery.

Revenues from our intermediate pipelines were $7.8$7.5 million, an increaseconsistent with the third quarter of $1.2 million, on shipments averaging 151.6 mbpd compared to 142.42020. Shipments averaged 136.4 mbpd for the third quarter of 2016. These volume increases were principally due to increased shipments on our New Mexico intermediate pipelines in line with increased production at HFC's Navajo refinery.
Revenues from our crude pipelines were $14.1 million, a decrease of $2.9 million, on shipments averaging 267.9 mbpd2021 compared to 271.3142.8 mbpd for the third quarter of 2016. This2020. The decrease in volumes was mainly due to lower throughputs on our intermediate pipelines servicing HollyFrontier's Navajo refinery while revenue decrease isremained constant mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $32.3 million, consistent with the third quarter of 2020. Shipments averaged 408.0 mbpd compared to 404.3 mbpd for the third quarter of 2020. The increased volume was mainly 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.pipeline systems in Wyoming and Utah.


Revenues from terminal, tankage and loading rack fees were $35.7$33.3 million, an increasea decrease of $1.3$5.7 million compared to the third quarter of 2016.2020. Refined products and crude oil terminalled in the facilities averaged 495.5472.2 mbpd compared to 505.8459.3 mbpd for the third quarter of 2016.2020. The revenue increases areincrease in volume was mainly the result of higher throughputs at HollyFrontier's El Dorado refinery. Revenues decreased mainly due to increased reimbursablelower on-going revenues on our Cheyenne assets as a result of the conversion of the HollyFrontier Cheyenne Refinery to renewable diesel production and reclassifications of certain tariffs and fees from revenue for projects managed by HEP and reimbursed by HFC.to interest income under sales-type lease accounting.


Revenues fromrefinery processing units were $20.6$21.9 million, an increase of $16.4$1.5 million oncompared to the third quarter of 2020, and throughputs averaging 61.5averaged 72.3 mbpd compared to 46.562.0 mbpd for the third quarter of 2016. This2020. The increase in revenue and volume is primarilyvolumes was mainly due to theincreased throughput for both our Woods Cross refineryand El Dorado processing units acquiredunits. Revenues increased mainly due to higher natural gas recoveries in revenues. Revenues did not increase in proportion to the fourth quarter of 2016.increase in volumes mainly due to contractual minimum volume guarantees.


Operations Expense
Operations (exclusive of depreciation and amortization)amortization and goodwill impairment) expense was $42.8 million for the three months ended September 30, 2017, increased by $3.92021, an increase of $2.8 million compared to the third quarter of 2020. The increase was mainly due to higher natural gas costs and employee costs for the three months ended September 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 30, 2017, increased2021 decreased by $0.1$4.4 million compared to the three months ended September 30, 2016.2020. The decrease was mainly due to the acceleration of depreciation on certain of our Cheyenne tanks in 2020.


General and Administrative
General and administrative costs for the three months ended September 30, 2017,2021 increased by $1.0$1.5 million compared to the three months ended September 30, 2016,2020, mainly due to higher legal and consulting costsprofessional expenses associated with our agreement, pursuant to which 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.Sinclair acquisition.


Equity in Earnings of Equity Method Investments
Three Months Ended September 30,
Equity Method Investment20212020
(in thousands)
Osage Pipe Line Company, LLC$1,090 $219 
Cheyenne Pipeline LLC1,654 533 
Cushing Connect Terminal Holdings LLC945 564 
Total$3,689 $1,316 

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Table of
 Three Months Ended September 30,
Equity Method Investment2017 2016
 (in thousands)
SLC Pipeline LLC$1,030
 $1,283
Frontier Aspen LLC1,662
 586
Osage Pipe Line Company, LLC1,119
 975
Cheyenne Pipeline LLC1,261
 923
Total$5,072
 $3,767
Equity in earnings of Osage Pipe Line Company, LLC increased for the three months ended September 30, 2021, mainly due to higher throughput volumes. Equity in earnings of Cheyenne Pipeline LLC increased for the three months ended September 30, 2021, mainly due to the recognition in revenue of prior contractual minimum commitment billings. Equity in earnings of Cushing Connect Terminal Holdings LLC increased for the three months ended September 30, 2021, mainly due to lower operating expenses.


Interest Expense, including Amortization
Interest expense for the three months ended September 30, 2017,2021, totaled $14.1$13.4 million, a decrease of $0.4$0.7 million compared to the three months ended September 30, 2016.2020. The decrease was mainly due to lower average borrowings outstanding under our senior secured revolving credit facility during the third quarter of 2021. Our aggregate effective interest rates were 4.5%3.7% and 5.3%3.6% for the three months ended September 30, 20172021 and 2016,2020, respectively.


State Income Tax Expense
We recorded state income tax benefit of $69,000$4,000 and a state income tax expense of $61,000$34,000 for the three months ended September 30, 20172021 and 2016,2020, respectively. All tax expense is solely attributable to the Texas margin tax.



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Results of Operations—Nine Months Ended September 30, 20172021 Compared with Nine Months Ended September 30, 20162020


Summary
Net income attributable to Holly Energy Partnersthe partners for the nine months ended September 30, 2017,2021, was $109.0$169.3 million ($1.60 per basic and diluted limited partner unit) compared to $116.9$119.1 million ($1.13 per basic and diluted limited partner unit) for the nine months ended September 30, 2016. The decrease in earnings is primarily due to (a) a charge of $12.2 million related to the early redemption of our previously outstanding $300 million, 6.5% Senior Notes (the “6.5% Senior Notes”), due in 2020, (b) higher interest expense of $5.1 million, and (c) lower refined product pipeline revenues of $7.7 million offset by (d) earnings from our Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Revenues2020. Results for the nine months ended September 30, 2017,2021, include special items that collectively increased net income attributable to the recognitionpartners by a total of $3.5$18.9 million. These items include a gain on sales-type leases of prior shortfalls billed$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 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 duringpartners for the nine months ended September 30, 2017. Such deferred revenue will be recognized2020, included a gain on sales-type leases of $33.8 million, a loss on early extinguishment of debt of $25.9 million, a goodwill impairment charge of $35.7 million related to our Cheyenne reporting unit and a $6.1 million gain related to HEP’s pro-rate share of a business interruption insurance claim resulting from a loss at HollyFrontier’s Woods Cross Refinery. Excluding these items, net income attributable to the partners for the nine months ended September 30, 2021 and 2020, were $150.4 million ($1.43 per basic and diluted limited partner unit) and $140.8 million ($1.34 per basic and diluted limited partner unit), respectively. The increase in earnings either as (a) payment for shipments in excess of guaranteed levels, ifwas mainly due to higher volumes across our crude pipelines, higher interest income associated with sales-type leases 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.lower interest expense, partially offset by higher operating expenses.


Revenues
Revenues for the nine months ended September 30, 2017,2021, 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, offset by a $9.8 million decrease in revenues around assets serving HFC's Navajo refinery primarily due 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.

Revenues from our refined product pipelines were $93.5 million, a decrease of $7.7 million, on shipments averaging 205.3 mbpd compared to 204.1 mbpd for the nine months ended September 30, 2016. The decrease in revenues is primarily due to lower volumes on product pipelines due to the turnaround at HFC's Navajo refinery in the first quarter of 2017 as well as a higher amount of shortfalls recognized in revenue for the nine months ended September 30, 2016.

Revenues from our intermediate pipelines were $20.4 million, a decrease of $0.5 million, on shipments averaging 136.1 mbpd compared to 138.3 mbpd for the nine months ended September 30, 2016. These volume decreases were primarily due to the turnaround at HFC's Navajo refinery, which was partially offset by increases in production at the Navajo refinery after the turnaround.

Revenues from our crude pipelines were $47.9 million, a decrease of $5.2 million, on shipments averaging 268.7 mbpd compared to 279.0 mbpd for the nine months ended September 30, 2016. Revenues and 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 our crude gathering lines made in the third quarter of 2017.

Revenues from terminal, tankage and loading rack fees were $105.9$376.0 million, an increase of $4.3$5.6 million compared to the nine months ended September 30, 2016.2020. The increase was mainly attributable to increased volumes on our crude pipeline systems in Wyoming and Utah, the recognition of the $10 million termination fee related to the termination of HollyFrontier's minimum volume commitment on our Cheyenne assets and higher revenues on our refinery processing units partially offset by lower on-going revenues on our Cheyenne assets and our pipelines servicing Delek's Big Spring refinery as well as reclassifications of certain tariffs and fees from revenue to interest income under sales-type lease accounting.

Revenues from our refined product pipelines were $84.7 million, a decrease of $3.7 million compared to the nine months ended September 30, 2020. Shipments averaged 165.8 mbpd compared to 172.6 mbpd for the nine months ended September 30, 2020. The volume and revenue decreases were mainly due to lower volumes on pipelines servicing Delek's Big Spring refinery.

Revenues from our intermediate pipelines were $22.6 million, an increase of $0.1 million compared to the nine months ended September 30, 2020. Shipments averaged 131.9 mbpd compared to 137.8 mbpd for the nine months ended September 30, 2020. The decrease in volumes was mainly due to lower throughputs on our intermediate pipelines servicing HollyFrontier's Tulsa refinery while revenue remained relatively constant mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $94.9 million, an increase of $8.0 million compared to the nine months ended September 30, 2020. Shipments averaged 393.0 mbpd compared to 380.1 mbpd for the nine months ended September 30, 2020. The increases were mainly attributable to increased volumes on our crude pipeline systems in Wyoming and Utah.
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Revenues from terminal, tankage and loading rack fees were $108.4 million, a decrease of $4.4 million compared to the nine months ended September 30, 2020. Refined products and crude oil terminalled in the facilities averaged 489.9436.9 mbpd compared to 478.0451.0 mbpd for the nine months ended September 30, 2016. The volume2020. Volumes decreased mainly as a result of lower throughputs at HollyFrontier's Tulsa refinery as well as the cessation of petroleum refinery operations at HollyFrontier's Cheyenne Refinery. Revenues decreased mainly as a result of reclassifications of certain tariffs and fees from revenue increases are mainly due to our Tulsa crude tanks acquired on the last day of the first quarter of 2016 offset by the transfer of the El Paso terminal to HollyFrontier in the first quarter of 2016.interest income under sales-type lease accounting.


Revenues fromrefinery processing units were $57.5$65.4 million, an increase of $44.6$5.6 million on throughputs averaging 63.9compared to the nine months ended September 30, 2020. Throughputs averaged 69.9 mbpd compared to 46.460.6 mbpd for the nine months ended September 30, 2016. 2020. The increasesincrease in revenue and volume is primarilyvolumes was mainly due to theincreased throughput for both our Woods Cross refineryand El Dorado processing units acquired in the fourth quarterunits. 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 months ended September 30, 2017,2021, increased by $13.4$16.5 million compared to the nine months ended September 30, 2016.2020. The increase is primarilywas 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.
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Depreciation and Amortization
Depreciation and amortization for the nine months ended September 30, 2017, increased2021, decreased by $6.5$3.3 million compared to the nine months ended September 30, 2016. 2020. The increase isdecrease was mainly due to the acceleration of depreciation from the Woods Cross refinery processing units acquiredon certain of our Cheyenne tanks in the fourth quarter2020 as well as retirement of 2016.assets due to sales-type lease accounting.


General and Administrative
General and administrative costs for the nine months ended September 30, 2017,2021, increased $0.3by $2.1 million compared to the nine months ended September 30, 2016, 2020 mainly due to higher legal and consulting costs offset by decreased employee compensation.professional expenses incurred in the nine months ended September 30, 2021.


Equity in Earnings of Equity Method Investments
In
Nine Months Ended September 30,
Equity Method Investment20212020
(in thousands)
Osage Pipe Line Company, LLC2,726 1,599 
Cheyenne Pipeline LLC3,428 2,693 
Cushing Connect Terminal Holdings LLC2,721 894 
Total$8,875 $5,186 

Equity in earnings of Osage Pipe Line Company, LLC increased for the firstnine months ended September 30, 2021, mainly due to higher throughput volumes. Equity in earnings of Cheyenne Pipeline LLC increased for the nine months ended September 30, 2021, mainly due to the recognition in revenue of prior contractual minimum commitment billings. Equity in earnings of Cushing Connect Terminal Holdings LLC increased for the nine months ended September 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 Investments2017 2016
 (in thousands)
SLC Pipeline LLC$2,053
 $3,397
Frontier Aspen, LLC3,813
 3,049
Osage Pipe Line Company, LLC1,889
 2,423
Cheyenne Pipeline LLC3,210
 1,286
Total$10,965
 $10,155


Interest Expense, including Amortization
Interest expense for the nine months ended September 30, 2017,2021, totaled $41.4$40.6 million, an increasea decrease of $5.1 million compared to the nine months ended September 30, 2016.2020. The increase is primarilydecrease was mainly due to the $400 million 6% Senior Notes issued July 19, 2016, and a higherlower average balanceborrowings outstanding on the Credit Agreement.our senior secured revolving credit facility and refinancingour $500 million 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%3.7% and 4.6%3.8% for the nine months ended September 30, 20172021 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$60,000 and $210,000$110,000 for the nine months ended September 30, 20172021 and 2016,2020, respectively. All tax expense is solely attributable to the Texas margin tax.




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LIQUIDITY AND CAPITAL RESOURCES


Overview
We have a $1.4 billionIn April 2021, we amended our senior secured revolving credit facility (the “Credit Agreement”) expiring indecreasing 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 containscontinues to provide for an accordion feature givingthat allows us the ability to increase commitments under the size of the facility byCredit Agreement up to $300 million with additional lender commitments.a maximum amount of $1.7 billion.


During the nine months ended September 30, 2017,2021, we received advances totaling $628$210.5 million and repaid $431 million, resulting in a net increase of $197$283.5 million under the Credit Agreement, resulting in a net decrease of $73.0 million and an outstanding balance of $750$840.5 million at September 30, 2017. We2021 under the Credit Agreement. As of September 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 $359.5 million. Amounts repaid under our credit facilitythe 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
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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 maturing5% 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 $300existing $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. ForWe did not issue any units under this program during the nine months ended September 30, 2017,2021. As of September 30, 2021, HEP has issued 1,538,4522,413,153 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 SECSecurities 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 wouldare 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. Future securities issuances, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.


We reduced our quarterly distribution to $0.35 per unit beginning with the distribution for the first quarter of 2020, representative of our 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.

In February, May and August 2021, we paid a regular quarterly cash distributionsdistribution 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 increaseddecreased by $3.8$9.2 million during the nine months ended September 30, 2017.2021. The cash flows provided by operating activities of $177.5$240.8 million were greaterless than the cash flows used for financing activities of $145.0$182.2 million and investing activities of $28.7$67.7 million. Working capital increaseddecreased by $13.2$11.1 million to $5.4$3.1 million at September 30, 2017,2021, from a negative $7.8$14.2 million at December 31, 2016.2020.


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Cash Flows—Operating Activities
Cash flows from operating activities decreased increased by $0.5$15.7 million from $178.0$225.0 million for the nine months ended September 30, 2016,2020, to $177.5$240.8 million for the nine months ended September 30, 2017.2021. The increase was mainly due to higher cash receipts from customers and lower payments for interest expenses partially offset by higher payments for operating costs and expenses during the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020.


Cash Flows—Investing Activities
Cash flows used for investing activities were $28.7$67.7 million for the nine months ended September 30, 2017,2021, compared to $137.1$39.4 million for the nine months ended September 30, 2016, a decrease2020, an increase of $108.5$28.3 million. During the nine months ended September 30, 20172021 and 2016,2020, we invested $30.7$78.6 million and $48.2$38.6 million, respectively, in additions to properties and equipment, respectively. During the nine months ended September 30, 2017 and 2016, we alsoequipment. We received $1.2$3.5 million and $1.7 million for distributions in excess of equity in earnings and $7.4 million in proceeds from the sale of equity investments, respectively. Additionally, we have retrospectively adjusted our historical financial results for the nine months ended September 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 Pipelineassets during the nine months ended September 30, 2016.2021.
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Cash Flows—Financing Activities
Cash flows used for financing activities were $145.0$182.2 million for the nine months ended September 30, 2017,2021, compared to $48.7$180.8 million for the nine months ended September 30, 2016,2020, an increase of $96.3$1.4 million. During the nine months ended September 30, 2017,2021, we received $628.0$210.5 million and repaid $431.0$283.5 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$112.4 million in regular quarterly cash distributions to our general and limited partners and $5.0$8.7 million to our noncontrolling interest.interests. We received $21.3 million in contributions from noncontrolling interests during the nine months ended September 30, 2021. During the nine months ended September 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$219.5 million and repaid $642.5$237.0 million in advances under the Credit Agreement. We paid $138.8$137.4 million in regular quarterly cash distributions to our general and limited partners, and distributed $3.8$7.8 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 thefor issuance of our 6%5% Senior Notes and $22.8paid $522.5 million from the issuance of common units underto retire our continuous offering program.6% Senior Notes. In addition, we received $55.0$15.4 million for Woods Cross processing units expendituresin contributions from HFC.noncontrolling interests during the nine months ended September 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 forecastingOur current 2021 capital forecast is comprised of approximately $15 million to spend $9$20 million for maintenance capital expenditures, $2 million to $4 million for refinery unit turnarounds and approximately $37$40 million to $45 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-ownedwholly owned subsidiary subject to redemption to the extent that HFC is entitled to a 50%
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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.

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Credit Agreement
We have aIn 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 into $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 containscontinues to provide for an accordion feature givingthat allows us the ability to increase the size ofcommitments under the facility byCredit Agreement up to $300 million with additional lender commitments.a maximum amount of $1.7 billion.


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-ownedwholly owned subsidiaries. The Credit Agreement requires us to maintain compliance with certain financial covenants consisting of total leverage, senior secured leverage, and interest coverage. It also limits or restricts our ability to engage in certain activities. If, at any time prior to the expiration of the Credit Agreement, HEP obtains two investment grade credit ratings, the Credit Agreement will become unsecured and many of the covenants, limitations and restrictions will be eliminated.


We may prepay all loans 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 30, 2017.2021.


Senior Notes
On January 4, 2017,As of September 30, 2021, we redeemed the $300had $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.


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 30, 2017.2021. At any time when the 6%5% Senior Notes are rated investment grade by botheither Moody’s andor 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 wholly-owned subsidiaries.existing wholly owned 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		September 30,
2021		December 31,
2020
 (In thousands) (In thousands)
Credit Agreement $750,000
 $553,000
Credit Agreement$840,500 913,500 
    
6% Senior Notes    
5% Senior Notes5% Senior Notes
Principal 500,000
 400,000
Principal500,000 500,000 
Unamortized debt issuance costs (4,934) (6,607)Unamortized debt issuance costs(7,191)(7,897)
 495,066
 393,393
492,809 492,103 
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$1,333,309 $1,405,603 

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


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Contractual Obligations
There were no significant changes to our long-term contractual obligations during this period.the quarter ended September 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 months ended September 30, 20172021 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 nine months of 2021 increased by 7.6% over the first nine 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 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.


Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.
We have an environmental agreement with AlonDelek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from AlonDelek in 2005, under which AlonDelek 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 30, 2017,2021, we havehad an accrual of $6.4$4.6 million that relatesrelated 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
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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 UnitCredit Losses Measurement
In April 2015, an accounting standard updateJune 2016, ASU 2016-13, “Measurement of Credit Losses on Financial Instruments,” was issued requiring changes tomeasurement 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 thereporting date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculatingbased on historical earnings per unit. We adopted thisexperience, 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, results2020. 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.


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At September 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 30, 2017,2021, the fair value of our 6%5% Senior Notes was $524.4$506.8 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6%5% Senior Notes at September 30, 2017,2021 would result in a change of approximately $15$13.1 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 30, 2017,2021, borrowings outstanding under the Credit Agreement were $750$840.5 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’sSEC’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 30, 2017,2021, at a reasonable level of assurance.


(b) Changes in internal control over financial reporting
ThereDuring the three months ended September 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 regulatoryother 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 believeand 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 materialmaterially adverse impacteffect 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,I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2020 and in Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021. In addition to the other information set forth in this quarterly report, you should consider carefully the factorsinformation discussed in our 20162020 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 20162020 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 does 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 (the “HSR Act”), with respect to the acquisition. On August 23, 2021, each of HollyFrontier and Sinclair filed its respective premerger notification and report regarding the Sinclair Transactions with the U.S. Department of Justice and the U.S. Federal Trade Commission (the “FTC”) under the HSR Act. On September 22, 2021, HFC and Sinclair each received a request for additional information and documentary material (“Second Request”) from the FTC in connection with the FTC’s review of the Sinclair Transactions. Issuance of the Second Request extends the waiting period under the HSR Act until 30 days after both HollyFrontier and Sinclair have substantially complied with the Second Request, unless the waiting period is terminated earlier by the FTC or the parties otherwise commit not to close the Sinclair Transactions for some additional period of time. HollyFrontier and Sinclair are cooperating with the FTC staff in its review. We have incurred and will continue to 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.

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:

•the inability to successfully integrate the Sinclair business into the HEP business in a manner that permits us to achieve the revenue and cost savings that we announced as anticipated from the acquisition;
•complexities associated with managing the larger, integrated business;
•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the acquisition;
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•integrating personnel from the two companies while maintaining focus on providing consistent, high-quality products and services;
•loss of key employees;
•integrating relationships with customers, vendors and business partners;
•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
•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 or have communicated from this integration or that these benefits will be achieved within the anticipated time frame.

Litigation relating to the Sinclair acquisition could result in substantial costs to HEP or an injunction preventing the completion of the Sinclair acquisition.

Securities class action lawsuits, derivative and related 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.

Lawsuits that may be brought against us, have been or may be brought against HollyFrontier, and/or our or HollyFrontier’s directors could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the acquisition agreement already implemented, issue additional disclosures and to otherwise enjoin the parties from consummating the Sinclair acquisition. HollyFrontier and the members of HollyFrontier’s board of directors were named as defendants in a lawsuit filed in Harris County, Texas, brought by an alleged HollyFrontier shareholder challenging the Sinclair acquisition and seeking, among other things, injunctive relief to enjoin and/or rescind the acquisition agreement and make additional or corrective disclosures. An additional lawsuit filed by an alleged HollyFrontier shareholder in the United States District Court for the Southern District of New York asserts claims under Section 14(a) of the Exchange Act and SEC Rule 14a-9 and claims under Section 20(a) of the Exchange Act against HollyFrontier and the members of HollyFrontier’s board of directors, and seeks, among other things, to enjoin and/or rescind the acquisition agreement and require defendants to amend the related proxy statement, and, if they do not, to recover damages. Additional lawsuits in connection with the Sinclair acquisition may be filed in the future in federal or state courts.

The outcome of these lawsuits or any other lawsuit that may be filed challenging the Sinclair acquisition is uncertain. One of the conditions to the closing of the Sinclair acquisition is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case, that prohibits or makes illegal the closing of the Sinclair acquisition. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Sinclair acquisition or delaying the shareholder vote, that injunction may delay or prevent the Sinclair acquisition from being completed within the expected timeframe or at all, which could result in substantial costs to us and may adversely affect our business, financial position, results of operations and cash flows. Relatedly, the defense or settlement of any lawsuit or claim that remains unresolved at the time the Sinclair acquisition is completed may adversely affect our business, financial condition, results of operations and cash flows and result in substantial costs to us.


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 thethis Quarterly Report on Form 10-Q.


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Exhibit Index
Exhibit
Number		Description
Exhibit
Number
2.1†		Description
2.1
Membership Interest PurchaseContribution Agreement, between Plains Pipeline, L.P. and HEP Casper SLC LLC, dated as of August 7, 20172, 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 datedfiled on August 10, 2017,3, 2021, File No. 1-3225)1-32225)..

2.23.1
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
FirstSecond 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).
3.53.2
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 -HEP Operating Company, L.P. (incorporated by reference to Exhibit 3.2 of Registrant’s Quarterly Report on Form 10-Q for itsthe quarterly period ended June 30, 2004, File No. 1-32225).
3.93.3
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).
3.103.4
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).
3.113.5
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 datedfiled on May 3, 2011, File No. 1-32225).
3.123.6
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).
4.110.1
Second Supplemental Indenture, datedAmendment to Seventh Amended and Restated Master Throughput Agreement, entered into as of July 26, 2017,27, 2021, effective as of May 1, 2021, by and amongbetween 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. (IncorporatedPartners – Operating L.P. (incorporated by reference to Exhibit 4.110.3 of the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2017,2021, File No. 1-3225)1-32225).
10.1*10.2†
First Amendment to Fourth Amended and Restated Master Lease and AccessUnitholders Agreement, dated as of October 13, 2017August 2, 2021, by and among certain subsidiaries of Holly Energy Partners, L.P., Holly Logistic Services, L.L.C., Navajo Pipeline Co., L.P., The Sinclair Companies, and certain subsidiaries of HollyFrontier Corporation.

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10.2
Third Amended and Restated Credit Agreement, dated July 26, 2017, by and among the Registrant, certain of its affiliatesunitholders set forth on Schedule I thereto, as guarantors, Wells Fargo Bank, National Association and certain other leaders party theretomay be amended from time to time (incorporated by reference to Exhibit 10.1 of the Registrants’Registrant’s Current Report on Form 8-K dated July 31, 2017,filed on August 3, 2021, File no.No. 1-32225).

10.3
Amendment to Equity DistributionLetter Agreement, dated as of July 28, 2017,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).
10.4*+
Second Amendment to the Registrant, HEP Logistics Holdings,Holly Energy Partners, L.P., Long-Term Incentive Plan, effective October 27, 2021.
10.5*+
Form of Performance Unit Agreement (Executive).
10.6*+
Form of Phantom Unit Agreement (Employee).
10.7*+
Form of Notice of Grant of Phantom Units (Employee).
10.8*+
Form of Phantom Unit Agreement (Non-Employee Director Award).
10.9*+
Form of Notice of Grant of Phantom Unit Agreement (Non-Employee Director Award).
10.10+
Consulting Agreement between Holly Logistics Services, L.L.C. and Citigroup Global Markets Inc., Goldman, Sachs & Co., and Merrill Lynch, Pierce, Fenner & Smith Incorporated. (Incorporated by reference 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 SeptemberMark Cunningham, effective February 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 therein2022 (incorporated by reference to Exhibit 10.1 of the Registrants’Registrant’s Current Report on Form 8-K dated September 25, 2017,filed on October 29, 2021, File no. 132225)No. I-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 30, 2017,2021 formatted in XBRL (ExtensibleiXBRL (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.
104Cover 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 Registrantregistrant 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, 20173, 2021/s/    Richard L. Voliva IIIJohn Harrison
Richard L. Voliva IIIJohn Harrison
ExecutiveSenior Vice President, and

Chief Financial Officer
and Treasurer
(Principal Financial Officer)
Date: November 2, 20173, 2021/s/    Kenneth P. Norwood
Kenneth P. Norwood
Vice President and Controller

(Principal Accounting Officer)
 



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