UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
ý☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended December 31, 20172022
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
75201-1507
Dallas
Texas75201-1507
(Address of principal executive offices)(Zip Code)
(214) 871-3555
Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to 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
Common Limited Partner Units

Securities registered pursuant to 12(g) of the Act:
None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ý☒    No  ¨☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes  ¨☐     No  ý☒
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.       ý☐
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”filer,” “smaller reporting company” and “smaller reporting“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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes ¨☐    No  ý☒
TheOn June 30, 2022, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the common limited partner units held by non-affiliates of the registrant was approximately $1.2$1.1 billion, on June 30, 2017,based upon the last day of the registrant's most recently completed second fiscal quarter, based on the last salesclosing price as quoted on the New York Stock Exchange on such date.
The number (This is not deemed an admission that any person whose shares were not included in the computation of the registrant’s outstandingamount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.)
126,440,201 shares of common limited partnerspartner units atwere outstanding on February 20, 2018 was 105,268,955.15, 2023.
 __________________________________________________________________________________________
DOCUMENTS INCORPORATED BY REFERENCE: None








TABLE OF CONTENTS


Item Page
PART I
3
1. and 2.
Business and Properties
7
1A.
26
1B.
49
3.
49
4.
50
PART II
5.
51
6.[Reserved]
51
7.
52
7A.
70
8.
71
9.
113
9A.
113
9B.
113
9C.
113
PART III
10.
115
11.
126
12.
147
13.
150
14.
154
PART IV
15.
156
157
162


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Item Page
 PART I 
   
Forward-Looking Statements
3
   
1. and 2.
Business and Properties
5
1A.
Risk factors
19
1B.
Unresolved staff comments
37
3.
Legal proceedings
37
4.
Mine safety disclosures
37
   
 PART II 
   
5.
Market for the Registrant’s common units, related unitholder matters and issuer purchases of common units
38
6.
Selected financial data
40
7.
Management’s discussion and analysis of financial condition and results of operations
44
7A.
Quantitative and qualitative disclosures about market risk
60
8.
Financial statements and supplementary data
61
9.
Changes in and disagreements with accountants on accounting and financial disclosure
98
9A.
Controls and procedures
98
9B.
Other information
98
   
 PART III 
   
10.
Directors, executive officers and corporate governance
99
11.
Executive compensation
110
12.
Security ownership of certain beneficial owners and management and related unitholder matters
135
13.
Certain relationships and related transactions, and director independence
137
14.
Principal accounting fees and services
141
   
 PART IV 
   
15.
Exhibits and Financial Statement Schedules
143
   
Index to exhibits
144
   
Signatures
149






PART I








FORWARD-LOOKING STATEMENTS


This Annual Report on Form 10-K 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-K, including, but not limited to, thosestatements regarding future operating results, our capital allocation strategy, funding of capital expenditures and distributions, distributable cash flow coverage and leverage targets, and statements under “Business”, “Risk Factors” and “Properties” in Items 1 1A and 22. “Business and Properties,” Item 1A. “Risk Factors,” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. Forward lookingForward-looking statements use words such as “anticipate,” “project,” "will," “expect,” “plan,” “goal,” “forecast,” “strategy,” “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 and increasing societal expectations that companies address climate change;
•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 HollyFrontierHF Sinclair Corporation, Delek US Holdings, Inc.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 operations and integrate futurethe operations we have acquired operations;or may acquire, including the recently acquired Sinclair Transportation Company LLC business;
•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 pipelinepipelines, terminal facilities and refinery processing units, due to reductions in demand, accidents, unexpected leaks or spills, unscheduled shutdowns, infection in the workforce, weather events, civil unrest, expropriation of assets, and other economic, diplomatic, legislative, or political events or developments, terrorism, cyberattacks, or other catastrophes or disruptions affecting our operations, terminal facilities;facilities, machinery, pipelines and other logistics assets, equipment, or information systems, or any of the foregoing of our suppliers, customers, or third-party providers or lower gross margins due to the economic impact of the COVID-19 pandemic, inflation and labor costs, and any potential asset impairments resulting from, or the failure to have adequate insurance coverage for or receive insurance recoveries 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 and increases in interest rates;
•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;
•uncertainty regarding the effects and duration of global hostilities, including the Russia-Ukraine war, and any associated military campaigns which may disrupt crude oil supplies and markets for refined products and create instability in the financial markets that could restrict our ability to raise capital;
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•general economic conditions;conditions, including economic slowdowns caused by a local or national recession or other adverse economic condition, such as periods of increased or prolonged inflation;
•the impact of recent or proposed changes in the tax laws and regulations that affect master limited partnerships; and
•other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission (the “SEC”) filings.


Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, 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 this Form 10-K under “Risk“Business and Properties” in Items 1 and 2,“Risk Factors” in Item 1A.1A and in conjunction with the discussion in this Form 10-K in “Management's Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.



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INDEX TO DEFINED TERMS AND NAMES


The following terms and names that appear in this form 10-K are defined on the following pages:
401(k) Plan136
6%5% Senior Notes2142
6.5% Senior NotesAAI49150
DelekAllocation Date550
bpdASC668
Credit AgreementASC 8421668
CWAASU2468
EBITDAbpd419
Expansion capital expendituresBoard16117
FERCBLM638
FCCBusiness Combination Agreement1481
Frontier AspenChange in Control Policy15137
Frontier PipelineChange in Control Agreement8137
GAAPCheyenne Refinery4220
Guarantor subsidiariesCISA9141
HEPClawback Policy5139
HEP LogisticsCOBRA5137
HLSContribution Agreement581
HFCCorps535
IRAsCredit Agreement3662
LACTCushing Connect Joint Venture1019
LIBORCushing Connect JV Terminal7919
LPGCushing Connect Pipeline519
MagellanCWA635
Maintenance capital expendituresData protection obligations1641
mbblsEBITDA657
MMSCFDEffectively connected income949
Mid-AmericaESG727
Non-GuarantorExchange Act91114
Omnibus AgreementFASB ASC Topic 71816126
OsageFCC1419
ParentFERC918
PlainsFrontier Pipeline611
PHMSAGAAP1657
PPIGuarantor subsidiaries7107
PredecessorHEP407
SCADAHEP Cushing1319
SECHEP Logistics5116
Secondment AgreementHFC167
SLC PipelineHFC Merger87
UNEVHFC Transaction87
Woods Cross OperatingHF Sinclair157
HLS7
IBR68
ICA22
Incentive Compensation139
IRS27

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Long-Term Incentive Plan125
LPGs8
mbbls9
Meridian124
Mid-America9
MMPL14
MMSCFD12
non-employee directors125
NDC38
NEPA35
NQDC Plan125
NYSE118
NWP35
Omnibus20
Osage58
Parent107
Parent Merger Sub7
Partnership71
PCAOB72
PHMSA21
Plains10
PMLP91
PPI9
Presiding Director117
REH7
RINs81
SCC36
SEC4
Secondment Agreement20
Sinclair Oil7
Sinclair Transportation7
SLC Pipeline11
SOFR70
Target Company7
TSA41
UNEV7
Unitholders Agreement88
VIE91

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Items 1 and 2. Business and Properties


OVERVIEW
Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership engaged principally in the business of operating a system of petroleum product and crude pipelines, storage tanks, distribution terminals and loading rack facilities in Colorado, Idaho, Iowa, Kansas, Missouri, Nevada, New Mexico, Oklahoma, Texas, Utah, Washington and Wyoming and refinery processing units in West Texas, New Mexico, Utah Nevada, Oklahoma, Wyoming, Kansas, Arizona, Idaho and Washington.Kansas. We were formed in Delaware in 2004 and maintain our principal corporate offices at 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Our telephone number is 214-871-3555 and our internet website address is www.hollyenergy.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Director,Vice President, Investor Relations at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission (“SEC”)SEC website is available on our website on the Investors page. Also available on our website are copies of our Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. In this document, the words “we,” “our,” “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person. “HFC”“HF Sinclair” refers to HollyFrontierHF Sinclair Corporation and its subsidiaries, other thanexcluding HEP and its subsidiaries and other than Holly Logistic Services, L.L.C. (“HLS”), a subsidiary of HollyFrontier CorporationHF Sinclair that is the general partner of theultimate general partner of HEP and manages HEP.
We
On March 14, 2022 (the “Closing Date”), HollyFrontier Corporation (“HFC”) and HEP announced the establishment of HF Sinclair Corporation, a Delaware corporation (“HF Sinclair”), as the new parent holding company of HFC and HEP and their subsidiaries, and the completion of their respective acquisitions of Sinclair Oil Corporation (now known as Sinclair Oil LLC (“Sinclair Oil”)) and Sinclair Transportation Company LLC (“Sinclair Transportation”) from The Sinclair Companies (now known as REH Company and referred to herein as “REH Company”). On the Closing Date, pursuant to that certain Business Combination Agreement, dated as of August 2, 2021 (as amended on March 14, 2022, the “Business Combination Agreement”), by and among HFC, HF Sinclair, Hippo Merger Sub, Inc., a wholly owned subsidiary of HF Sinclair (“Parent Merger Sub”), REH Company, and Hippo Holding LLC (now known as Sinclair Holding LLC), a wholly owned subsidiary of REH Company (the “Target Company”), HF Sinclair completed its acquisition of the Target Company by effecting (a) a holding company merger in accordance with Section 251(g) of the Delaware General Corporation Law whereby HFC merged with and into Parent Merger Sub, with HFC surviving such merger as a direct wholly owned subsidiary of HF Sinclair (the “HFC Merger”), and (b) immediately following the HFC Merger, a contribution whereby REH Company contributed all of the equity interests of the Target Company to HF Sinclair in exchange for shares of HF Sinclair, resulting in the Target Company becoming a direct wholly owned subsidiary of HF Sinclair (together with the HFC Merger, the “HFC Transactions”).

Additionally, on the Closing Date and immediately prior to consummation of the HFC Transactions, HEP acquired all of the outstanding equity interests of Sinclair Transportation from REH Company in exchange for 21 million newly issued common limited partner units of HEP (the “HEP Units”), representing 16.6% of the pro forma outstanding HEP Units with a value of approximately $349 million based on HEP’s fully diluted common limited partner units outstanding and closing unit price on March 11, 2022, and cash consideration equal to $329.0 million, inclusive of final working capital adjustments for an aggregate transaction value of $678.0 million (the “HEP Transaction” and together with the HFC Transactions, the “Sinclair Transactions”). The cash consideration was funded through a draw under HEP’s senior secured revolving credit facility. The HEP Transaction was conditioned on the closing of the HFC Transactions, which occurred immediately following the HEP Transaction.

Sinclair Transportation, together with its subsidiaries, owned REH Company’s integrated crude and refined products pipelines and terminal assets, including approximately 1,200 miles of integrated crude and refined product pipeline supporting the REH Company refineries and other third-party refineries, eight product terminals and two crude terminals with approximately 4.5 million barrels of operated storage. In addition, HEP acquired Sinclair Transportation’s interests in three pipeline joint ventures for crude gathering and product offtake including: Saddle Butte Pipeline III, LLC (25.06% non-operated interest); Pioneer Investments Corp. (49.995% non-operated interest); and UNEV Pipeline, LLC ("UNEV") (the 25% non-operated interest not already owned by HEP, resulting in UNEV becoming a wholly owned subsidiary of HEP).

References herein to HEP with respect to time periods prior to March 14, 2022, include HEP and its consolidated subsidiaries and do not include Sinclair Transportation and its consolidated subsidiaries (collectively, the “HEP Acquired Sinclair Businesses”). References herein to HEP with respect to time periods from and after March 14, 2022 include the operations of the HEP Acquired Sinclair Businesses.

References herein to HF Sinclair Corporation (“HF Sinclair”) with respect to time periods prior to March 14, 2022 refer to HFC and its consolidated subsidiaries and do not include the Target Company, Sinclair Transportation or their respective consolidated subsidiaries (collectively, the “HFS Acquired Sinclair Businesses”). References herein to HF Sinclair with respect
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to time periods from and after March 14, 2022 refer to HF Sinclair and its consolidated subsidiaries, which include the operations of the combined business operations of HFC and the HFS Acquired Sinclair Businesses.
Through our subsidiaries and joint ventures we own andand/or operate petroleum product and crude pipelines, terminal, tankage and loading rack facilities, and refinery processing units that support the refining and marketing operations of HFCHF Sinclair and other refineries in the Mid-Continent, Southwest and Northwest regions of the United States and Delek US Holdings, Inc.’s (“Delek”) refinery in Big Spring, Texas.States. At December 31, 2017, HFC2022, HF Sinclair owned approximately 59%47% of our outstanding common units as well as a non-economic general partner interest. Our assets are categorized into a Pipelines and Terminals segment and a Refinery Processing Unit segment. Segment disclosures are discussed in Note 1416 to our consolidated financial statements in Part II, Item 8.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons, providing other services at our storage tanks and terminals and charging a tolling fee per barrel or thousand standard cubic feet of feedstock throughput in our refinery processing units. We do not take ownership of products that we transport, terminal, store or process, and therefore, we are not directly exposed to changes in commodity prices.
We have a long-term strategic relationship with HFC.HF Sinclair that has historically facilitated our growth. Our future 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 the economic conditions discussed in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview”, we also expect over the longer term to continue to pursue purchases of logistic and other assets at HFC's existing refining locations in New Mexico, Utah, Oklahoma, Kansas and Wyoming. We also expect to work with HFCHF Sinclair on logistic asset acquisitions in conjunction with HFC’sHF Sinclair’s refinery acquisition strategies. Furthermore, we will continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.
On October 31, 2017, we closed on a restructuring transaction with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions.


PIPELINES AND TERMINALS


Pipelines


Our refined product pipelines transport light refined products from HFC’sHF Sinclair’s Navajo refinery in New Mexico and Delek’s Big Springa third party's refinery in Texas to their customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Utah, and OklahomaArizona, and from various refineries in Utah, Wyoming, and Montana (including HFC'sHF Sinclair's Woods Cross refinery in Utah)Utah, Parco refinery in Sinclair, Wyoming, and Casper refinery in Casper, Wyoming) to Las Vegas, Nevada, Utah and Cedar City, Utah.Colorado. We also have a product pipeline that transports light refined products from Olathe, Kansas to Carrollton, Missouri and Montrose, Iowa. The refined products transported in these pipelines include conventional gasolines, federal, state and local specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that include high- and low-sulfur diesel and jet fuel and liquefied petroleum gases ("LPGs"(“LPGs”) (such as propane, butane and isobutane).


Our intermediate product pipelines consist principally of three parallel pipelines that connect the Navajo refinery, Lovington and Artesia facilities. These pipelines primarily transport intermediate feedstocks and crude oil for HFC’sHF Sinclair’s refining operations in New Mexico. We also own pipelines that transport intermediate product and gas between HFC'sHF Sinclair's Tulsa East and West refinery facilities.facilities, and between HF Sinclair's Casper and Parco refineries.




Our crude pipelines consist of crude oil trunk, gathering and connection pipelines located in West Texas, New Mexico, Kansas, Oklahoma, Utah and Wyoming that deliver crude oil to HFC'sHF Sinclair's Navajo, El Dorado, andTulsa, Woods Cross, Parco and Casper refineries as well as other unaffiliated refineries.


Our pipelines are regularly inspected. Generally, other than as may be provided in certain pipelines and terminal agreements, substantially all of our pipelines are unrestricted as to the direction in which product flows and the types of crude and refined products that we can transport on them. The Federal Energy Regulatory Commission ("FERC"(“FERC”) regulates the transportation tariffs for interstate shipments on our refined product and crude oil pipelines and state regulatory agencies regulate the transportation tariffs for intrastate shipments on our pipelines.


HFCHF Sinclair shipped an aggregate of 63%79% of the petroleum products transported on our refined product pipelines, 97%100% of the throughput volumes transported on our intermediate pipelines, and 93%76% of the throughput on our crude pipelines in 2017.2022.


The following table details the average aggregate daily number of barrels of petroleum products transported on our pipelines in each of the periods set forth below for HFCHF Sinclair and for third parties.
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Years Ended December 31,
 Years Ended December 31, 20222021202020192018
 2017 2016 2015 2014 2013
Volumes transported for barrels per day ("bpd"):          
HFC 556,516
 542,762
 558,027
 457,014
 397,359
Volumes transported for barrels per day (“bpd”):Volumes transported for barrels per day (“bpd”):
HF SinclairHF Sinclair729,395 513,506 529,905 633,270 622,088 
Third parties 99,847
 75,909
 73,555
 64,055
 63,337
Third parties182,478 178,440 156,376 204,052 187,717 
Total 656,363
 618,671
 631,582
 521,069
 460,696
Total911,873 691,946 686,281 837,322 809,805 
Total barrels in thousands (“mbbls”) 239,572
 226,434
 230,527
 190,190
 168,154
Total barrels in thousands (“mbbls”)334,581 252,560 251,178 305,623 295,579 


Our pipeline assets are managed by geographic region; significant pipeline assets are grouped accordingly, and our major systems are described below.


Mid-Continent Region


Tulsa, Oklahoma Interconnect Pipelines
Five pipelines, totaling seven miles, move intermediate product and gas between HFC’sHF Sinclair’s Tulsa East and West refinery facilities.


El Dorado Crude Delivery PipelinePipelines
ThisThese two 2-mile pipeline supplies HFC'spipelines supply HF Sinclair's El Dorado Refinery facility with crude oil from HEP's El Dorado crude tankage. HFCHF Sinclair is the only shipper on this line.


Osage Pipe Line Company, LLC
This 135-mile pipeline, which FERC regulates, supplies HFC'sHF Sinclair's El Dorado Refinery with crude oil from Cushing, Oklahoma and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. HEP has a 50% interest in this entity and is the operator of the pipeline.


CheyenneCushing Connect Pipeline Holdings LLC
This 87-mile50-mile crude oil pipeline, which is regulated by the Oklahoma Corporation Commission, runs from Fort Laramie, WyomingCushing, Oklahoma to Cheyenne, Wyoming.HF Sinclair’s Tulsa East and West refinery facilities. HEP owns a 50% interest in this entity;entity and is the operator of the pipeline. The Cushing Connect Pipeline was placed into service at the end of the third quarter of 2021.

Midcon Products System
This 220-mile refined products pipeline, which is operatedregulated by an affiliate of Plains All American Pipeline, L.P. ("Plains").PHMSA, runs from Olathe, Kansas (Magellan Midstream Partners, LLC Olathe Terminal) and terminates at HEP’s Montrose, Iowa Products Terminal. It operates in two distinct segments, supplying refined petroleum products to two HEP terminal and tank farm facilities located near Carrollton, Missouri and Montrose, Iowa.


Southwest Region


Artesia, New Mexico to El Paso, Texas
These 371221 miles of pipeline are comprised of fivefour main segments which are regulated by the FERC. The segments primarily ship refined product produced at the Navajo refinery to El Paso terminals: (1) 156 miles of 6-inch pipeline from HFC's Navajo refinery to HFC's El Paso terminal, (2) 82 miles of 12-inch pipeline from HFC'sHF Sinclair's Navajo refinery to our Orla tank farm, (3)(2) 126 miles from our Orla tank farm to outside El Paso, (4)(3) seven miles from outside El Paso to HFC's El Paso terminal and (5)(4) six miles of 12-inch pipeline from outside El Paso to Magellan Midstream Partners' (“Magellan”)Magellan's El Paso terminal. There are two shippers on the latter three segments, HFC and Delek, and HFC is the only shipper on the first two segments.


Refined products destined to HFC'sHF Sinclair's El Paso terminal and Magellan's El Paso terminal are delivered to common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s truck rack for local and export delivery by tanker truck.





Artesia, New Mexico to Moriarty, New Mexico
The Artesia to Moriarty refined product pipeline consists of a 60 mile60-mile segment that extends from HFC'sHF Sinclair's Navajo refinery Artesia facility to White Lakes Junction, New Mexico, and another 155 mile155-mile segment that extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. HEP owns the segment from Artesia to White Lakes Junction and leases the segment from White Lakes Junction to Moriarty from Mid-America Pipeline Company, LLC ("Mid-America"(“Mid-America”) under a long-term lease agreement which expires in 2027.2027 with an option to renew for an additional 10 years. The current monthly lease payment is $535,000 (subject$604,000 (subject to adjustments for changes in Producer Price Index ("PPI"(“PPI”)) to the owner/operator, Mid-America. HFCHF Sinclair is the only shipper on this pipeline.


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Moriarty, New Mexico to Bloomfield, New Mexico
This 191-mile pipeline is leased from Mid-America and ships refined product from Moriarty to Western Refining'sMarathon Petroleum Corporation's terminal in Bloomfield and our Bloomfield terminal, which is currently idled. This pipeline is operated by Mid-America (or its designee), and HFCHF Sinclair is the only shipper on this pipeline.


Big Spring, Texas to Abilene and Wichita Falls, Texas
These two pipelines carry refined product produced at Delek's Big Spring refinery to the Abilene and Wichita Falls terminals and span 100 miles from Big Spring to Abilene and 227 miles from Big Spring to Wichita Falls. Delek is the only shipper on these pipelines.


Wichita Falls, Texas to Duncan, Oklahoma
This 47-mile, common carrier pipeline is regulated by the FERC and transports refined product from the Wichita Falls terminal to Delek's Duncan terminal. DelekThis pipeline is the only shipper on this pipeline.currently idle.


Midland, Texas to Orla, Texas
This 135-mile pipeline is used for the shipment of refined product from Midland to our tank farm at Orla (refined product produced at Delek's Big Spring refinery). Delek is the only shipper on this pipeline.


Intermediate pipelines between Lovington, New Mexico and Artesia, New Mexico
Two of the three 65-mile pipelines are used for the shipment of intermediate feedstocks, crude oil and LPGs from HFC'sHF Sinclair's Navajo refinery Lovington facility to its Artesia facility. The third pipeline is used to supply both HFC'sHF Sinclair's Navajo refinery Artesia and Lovington facilities with crude oil from the Barnsdall and Beeson gathering systems. This third pipeline can also connect to the Roadrunner pipeline (described below). HFCHF Sinclair is the primary shipper on these pipelines.


Roadrunner pipeline
The 69-mile Roadrunner crude oil pipeline connects the Navajo refinery Lovington facility to a terminal on the Centurion Pipeline in Slaughter, Texas that extends to Cushing, Oklahoma. This pipeline is currently used to deliver crude oil from Lovington to Slaughter, but has been reversed in prior years for the shipment of crude oil from Cushing, Oklahoma to the Navajo refinery Lovington facility.


New Mexico and Texas crude oil pipelines
The 802-mile network of crude oil gathering and trunk pipelines deliver crude oil to HFC’sHF Sinclair’s Navajo refinery from New Mexico and Texas. The crude oil trunk pipelines consist of nine pipeline segments that deliver crude oil to the Navajo refinery Lovington facility and fourteen pipeline segments that deliver crude oil to the Navajo refinery Artesia facility. The crude oil gathering pipelines connect crude leases and crude gathering hubs to the crude oil trunk pipeline system.


New Mexico crude expansion pipelines
HEP constructed threeThree pipelines to expand on the existing network of New Mexico crude oil pipelines discussed above. They include (1) the 46-mile Beeson pipeline which delivers crude oil from the crude oil gathering system to the Navajo refinery Lovington facility and the Roadrunner Pipeline, (2) the 61-mile Whites City crude pipeline which delivers crude oil from HEP's Whites City Road crude truck off-loading stationStation to Artesia Station, and (3) the 13-mile Bisti connector pipeline which delivers crude oil from HEP's Beeson Crude Station to the Plains Bisti Pipeline.


Northwest Region


Utah refined product pipelines
The Utah refined product pipelines consist of four pipeline segments: (1) a 2-mile segment from Woods Cross, UT to Pioneer Pipe Line Company'sInvestment Corp.'s terminal is used for product shipments to and through the Pioneer terminal, (2) another 2-mile4-mile segment is used to ship refined product from HFC'sHF Sinclair's Woods Cross refinery to the UNEV pipeline origin pump station, (3) a 4-mile segment from HFC'sHF Sinclair's Woods Cross refinery to Chevron Pipeline’sMPLX LP’s Salt Lake City products pipeline is used for product shipments from


HFC’s HF Sinclair’s Woods Cross refinery to Andeavor LogisticsMPLX LP's Northwest Pipeline origin station, and (4) a 1- mile1-mile segment is used to move refined product from Chevron's Salt Lake City refining facility into the UNEV pipeline origin pump station. HFCHF Sinclair is the only shipper on the first three formerpipeline segments and Chevrona third party is the only shipper on the fourth, common carrier pipeline segment.


UNEV refined product pipeline
The 427-mile UNEV products pipeline, which FERC regulates, is a common carrier pipeline used for the shipment of refined products from Woods Cross, Utah to terminals in Las Vegas, Nevada and Cedar City, Utah. This pipeline is owned by UNEV

Cheyenne Pipeline LLC ("UNEV").
This 87-mile crude oil pipeline, which FERC regulates, runs from Fort Laramie, Wyoming to Cheyenne, Wyoming. HEP owns a 75%50% interest in UNEV and HEPthis entity; the pipeline is the operatoroperated by an affiliate of this pipeline.Plains All American Pipeline, L.P. (“Plains”).

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SLC Pipeline
This 95-mile crude oil pipeline ("SLC Pipeline"(the “SLC Pipeline”), which FERC regulates, is used to transport crude into the Salt Lake City, Utah area from the Utah terminus of the Frontier Pipeline (described below) as well as crude flowing from Wyoming and UtahColorado via the Plains Rocky Mountain pipeline. HEP owns a 100% interest in this pipeline after purchasing the remaining 75% interest, effective October 31, 2017.Marathon Wamsutter system.


Frontier Aspen Pipeline
This 289-mile crude oil pipeline ("Frontier Pipeline"(the “Frontier Pipeline”), which FERC regulates, spans from Casper, Wyoming to Frontier Station, Utah through a connection to the SLC Pipeline.

Cheyenne Pipeline
This 94-mile crude oil pipeline, which FERC regulates, spans from Cheyenne, Wyoming to Guernsey, Wyoming and previously transported trucked crude gathered in Cheyenne to Guernsey. This pipeline is currently idle.

Guernsey Pipeline
This 115-mile crude oil pipeline spans from Guernsey, Wyoming to the Pathfinder station in Casper, Wyoming. There is a connection at Natural Bridge that allows injection from Saddle Butte who operates a gathering network out of the Powder River Basin. There is also a connection into the HF Sinclair refinery in Casper where crude oil is delivered.

Salvation Pipeline
This 114-mile bi-directional products pipeline spans between the HF Sinclair Casper and Parco refineries. It is a combination of three pipeline segments – 11.3 miles of 12” and two different segments of 8”. It is used to transport finished product as well as intermediates back and forth between the two refineries.

Casper 10” Pipeline
This 102-mile crude oil pipeline spans between Pathfinder station in Casper and the Parco refinery. It delivers a variety of blended sweet crude oils.

Pathfinder Pipeline
This 103-mile crude oil pipeline spans between Pathfinder station in Casper and the Parco refinery. It delivers a variety of blended sour crude oils.

Sand Draw Pipeline
This 61-mile crude oil pipeline spans from Sand Draw station near Riverton, Wyoming to Bairoil station in Bairoil, Wyoming. It delivers crude oil from the Beaver Creek and Big Sand Draw facilities to Bairoil station. There is an injection point three miles upstream of Bairoil station from the Bairoil oil field operated by Amplifier Energy.

Bairoil Pipeline
This 41-mile crude oil pipeline spans from Bairoil station in Bairoil, Wyoming to the Parco refinery in Sinclair, Wyoming. It delivers crude oil from the Beaver Creek, Big Sand Draw and Bairoil fields.

Medicine Bow Pipeline
This 205-mile refined product pipeline spans between the Parco refinery in Sinclair, Wyoming to the Denver Products Terminal in Henderson, Colorado. It is a combination of 166 miles of 6” and 39 miles of 10” pipe. It delivers finished products to the truck terminal.

Pioneer Pipeline
This 252-mile refined product pipeline, which FERC regulates, runs from Sinclair Station in Wyoming to the terminal in North Salt Lake City, Utah also owned by Pioneer Investments Corp. Through connections, this pipeline is also able to deliver refined products to our UNEV refined products pipeline. HEP owns a 100%49.995% interest in Pioneer Investments Corp. The pipeline and terminal are operated by an affiliate of Phillips 66 Company.

Saddle Butte Pipeline III, LLC
This crude oil pipeline gathering system collects crude oil from the Powder River Basin in Wyoming and primarily delivers into our Guernsey pipeline. HEP owns a 25.06% interest in this pipeline after purchasing the remaining 50% interest, effective October 31, 2017.entity.

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The following table sets forth certain operating data for each of our majority-owned refined product, intermediate and crude pipelines, most of which are described above. We calculate the capacity of our pipelines based on the throughput capacity for barrels of refined product, intermediate or crude that may be transported in the existing configuration; in some cases, this includes the use of drag reducing agents. 

Origin and DestinationDiameter
(inches)		Length
(miles)		Capacity
(bpd)
Refined Product Pipelines:
Artesia, NM to Orla, TX to El Paso, TX8/12221 95,000 
Artesia, NM to Moriarty, NM(1)
12/8215 27,000 
Moriarty, NM to Bloomfield, NM(1)(2)
8 191 14,400 
Big Spring, TX to Abilene, TX6/8100 20,000 
Big Spring, TX to Wichita Falls, TX6/8227 23,000 
Wichita Falls, TX to Duncan, OK(6)
6 47 21,000 
Midland, TX to Orla, TX8/10135 25,000 
Artesia, NM to Roswell, NM(6)
4 35 5,300 
Mountain Home, ID4 13 6,000 
Woods Cross, UT10/12/810 70,000 
Woods Cross, UT to Las Vegas, NV12 427 62,000 
Salt Lake City, UT to UNEV Pipeline, UT10 1 60,000 
Tulsa, OK(3)
Olathe, KS to Carrollton, MO8 8115,000 
Carrollton, MO to Montrose, IA8 13910,000 
Medicine Bow Pipeline6/1020530,000 
Aurora (Chase connection) Pipeline101530,000 
Dupont (Kaneb connection) Pipeline8324,000 
Intermediate Product Pipelines:
Lovington, NM to Artesia, NM8 65 48,000 
Lovington, NM to Artesia, NM10 65 72,000 
Lovington, NM to Artesia, NM16 65 98,400 
Tulsa, OK(4)
8/10/127     
Evans Junction to Artesia, NM(5)
8 12 107 
Salvation Pipeline8/12/811418,000 
Crude Pipelines:
Artesia Region GatheringVarious497 70,000 
West Texas GatheringVarious305 35,000 
Roadrunner Pipeline16 69 80,000 
Beeson Pipeline8/1046 95,000 
El Dorado Crude Delivery Pipeline16 4 165,000 
Bisti Connection Pipeline12 13 82,000 
Whites City Pipeline8 61 62,000 
SLC Pipeline16 95 120,000 
Frontier Pipeline16 289 72,000 
Bairoil Pipeline8 41 15,000 
Cheyenne Pipeline10 94 36,000 
Guernsey Pipeline10 115 50,000 
Casper Pipeline10 102 34,000 
Pathfinder Pipeline16 103 65,000 
Beaver Creek Pipeline4 10 7,000 
Sand Draw Pipeline8 61 18,000 

(1)The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and the Moriarty to Bloomfield pipeline is leased from Mid-America under a long-term lease agreement.
(2)Capacity for this pipeline is reflected in the information for the Artesia to Moriarty pipeline.
(3)Tulsa gasoline and diesel fuel connections to Magellan’s pipeline are less than one mile.
(4)The capacities of the three gas pipelines are 10 million standard cubic feet per day (“MMSCFD”), 22 MMSCFD and 10 MMSCFD, and the two liquid pipelines are 45,000 bpd and 60,000 bpd.
(5)The capacity is in MMSCFD per day.
(6)Pipeline is currently idled.

Origin and Destination 
Diameter
(inches)
 
Length
(miles)
 
Capacity
(bpd)
 
Refined Product Pipelines:       
Artesia, NM to El Paso, TX 6
 156
 19,000
 
Artesia, NM to Orla, TX to El Paso, TX 8/12
 221
 95,000
(1) 
Artesia, NM to Moriarty, NM(2)
 12/8
 215
 27,000
(3) 
Moriarty, NM to Bloomfield, NM(2)
 8
 191
 14,400
(3) 
Big Spring, TX to Abilene, TX 6/8
 100
 20,000
 
Big Spring, TX to Wichita Falls, TX 6/8
 227
 23,000
 
Wichita Falls, TX to Duncan, OK 6
 47
 21,000
 
Midland, TX to Orla, TX 8/10
 135
 25,000
 
Artesia, NM to Roswell, NM 4
 35
 5,300
(7) 
Mountain Home, ID 4
 13
 6,000
 
Woods Cross, UT 10/12/8
 8
 70,000
 
Woods Cross, UT to Las Vegas, NV 12
 427
 62,000
 
Salt Lake City, UT to UNEV Pipeline, UT 10
 1
 60,000
 
Tulsa, OK(4)
       
Intermediate Product Pipelines:       
Lovington, NM to Artesia, NM 8
 65
 48,000
 
Lovington, NM to Artesia, NM 10
 65
 72,000
 
Lovington, NM to Artesia, NM 16
 65
 98,400
 
Tulsa, OK(5)
 8/10/12
 7
     
(5) 
Evans Junction to Artesia, NM 8
 12
 107
(6) 
Crude Pipelines:       
Artesia Region Gathering Various
 497
 70,000
 
West Texas Gathering Various
 305
 35,000
 
Roadrunner Pipeline 16
 69
 62,400
 
Beeson Pipeline 8/10
 46
 95,000
 
El Dorado Crude Delivery Pipeline 16
 4
 165,000
 
Bisti Connection Pipeline 12
 13
 82,000
 
Whites City Pipeline 8
 61
 50,000
 
SLC Pipeline 16
 95
 105,000
 
Frontier Pipeline 16
 289
 72,000
 
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(1)Includes 15,000 bpd capacity on the Orla to El Paso segment of this pipeline, leased to Delek under capacity lease agreements.
(2)The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and the Moriarty to Bloomfield pipeline is leased from Mid-America under a long-term lease agreement.
(3)Capacity for this pipeline is reflected in the information for the Artesia to Moriarty pipeline.
(4)Tulsa gasoline and diesel fuel connections to Magellan’s pipeline are less than one mile.
(5)The capacities of the three gas pipelines are 10 million standard cubic feet per day (“MMSCFD”), 22 MMSCFD and 10 MMSCFD, and the two liquid pipelines are 45,000 bpd and 60,000 bpd.
(6)The capacity is in MMSCFD per day.
(7)Pipeline is currently idled.


Terminals, Loading Racks and Refinery and Renewable Diesel Facility Tankage


Our refined product terminals receive products from pipelines connected to HFC’sHF Sinclair’s refineries and Delek’s Big Spring refinery.other third party refineries. We then distribute them to HFCHF Sinclair and third parties, who in turn deliver them to end-users and retail outlets. Our terminals are generally complementary to our pipeline assets and serve HFC’s and Delek’sthe marketing activities of HF Sinclair and other customers. Terminals play a key role in moving product to the end-user market by providing the following services:
•distribution;
•blending to achieve specified grades of gasoline and diesel, including the blending of butane, ethanol and biodiesel;
•other ancillary services that include the injection of additives and filtering of jet fuel; and
•storage and inventory management.




Typically, our refined product terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that operates 24 hours a day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by our customers. In addition, nearly all of our terminals are equipped with truck loading racks capable of providing automated blending to individual customer specifications.


Our refined product terminals derive most of their revenues from terminalling fees paid by customers. We charge a fee for transferring refined products from the terminal to trucks or to pipelines connected to the terminal. In addition to terminalling fees, we generate revenues by charging our customers fees for storage, blending, injecting additives, and filtering jet fuel. HFCHF Sinclair currently accounts for the substantial majority of our refined product terminal revenues.


Our crude terminalterminals receives crude from the Osage pipelinecrude pipelines and derivestruck offloading racks owned by us and third-parties and derive most of itstheir revenues from throughput charges.


The table below sets forth the total average throughput for our refined product and crude terminals in each of the periods presented:
 Years Ended December 31,
 20222021202020192018
Refined products and crude terminalled for (bpd):
HF Sinclair560,038 391,698 393,300 422,119 413,525 
Third parties38,211 51,184 48,909 61,054 61,367 
Total598,249 442,882 442,209 483,173 474,892 
Total (mbbls)218,351 161,652 161,848 176,358 173,336 
  Years Ended December 31,
  2017 2016 2015 2014 2013
Refined products and crude terminalled for (bpd):          
HFC 428,001
 413,487
 391,292
 261,888
 255,108
Third parties 68,687
 72,342
 78,403
 69,100
 63,791
Total 496,688
 485,829
 469,695
 330,988
 318,899
Total (mbbls) 181,291
 177,813
 171,439
 120,811
 116,398


Our refinery and renewable diesel facility tankage consists of on-site tankage at HFC’s refineries.HF Sinclair’s refineries and renewable diesel facilities. Our refinery and renewable diesel facility tankage derives its revenues from fixed fees or throughput charges in providing HFC’sHF Sinclair’s refining and renewable diesel facilities with approximately 10,198,000 barrels 9,210,000 barrels of storage.


Our terminals, loading racks and refinery and renewable diesel tankage are managed by geographic region; significant assets are grouped accordingly and described below.


Mid-Continent Region

Cheyenne, Wyoming facility truck racks
The Cheyenne loading rack facilities consist of light refined product, heavy product and LPG truck racks. These racks load refined product and propane onto tanker trucks for delivery to markets in surrounding areas. Additionally, these facilities include four crude oil Lease Automatic Custody Transfer ("LACT") units that unload crude oil from tanker trucks.


El Dorado, Kansas crude tankage
On March 6, 2015, we acquired an existing crude tank farm from an unrelated party. TheThis crude tank farm is adjacent to HFC'sHF Sinclair's El Dorado Refinery and is used, primarily, to store and supply crude oil for this refinery facility. HFC is the main customer of this crude tank farm.


El Dorado, Kansas facility truck racks
The El Dorado loading rack facilities consist of a light refined products truck rack and a propane truck rack. These racks load refined products and propane onto tanker trucks for delivery to markets in surrounding areas.


Catoosa, Oklahoma terminal
The Catoosa terminal is a water port terminal close to HF Sinclair's Tulsa refinery and stores specialty lubricant products. HF Sinclair is the primary customer utilizing this terminal.

Cushing Connect Terminal Holdings LLC
This entity owns 1.5 million barrels of crude oil storage in Cushing, Oklahoma, which went in service during the second quarter of 2020. HEP owns a 50% interest in this entity; the terminal is operated by an affiliate of Plains.

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Tankage at HFCHF Sinclair refinery and renewable diesel facilities
At HFC's Cheyenne,HF Sinclair's El Dorado and Tulsa refinery facilities as well as HF Sinclair's Cheyenne renewable diesel facility, HEP owns refined product, intermediate and crude tankage that support these refineries in production and distribution. HFCHF Sinclair is the only customer utilizing these tanks. See “Agreements with HF Sinclair” below for a discussion of changes to HF Sinclair's use of assets located in Cheyenne, Wyoming.


Tulsa, Oklahoma facilities truck and rail racks
The Tulsa truck and rail loading rack facilities consist of loading racks located at HFC’sHF Sinclair’s Tulsa refinery West and East facilities. Loading racks at the Tulsa refinery West facility consist of rail and truck racks that load refined products and lube oil produced at the refinery onto rail cars and tanker trucks. Loading racks at the Tulsa refinery East facility consist of truck and rail racks at which we load refined products and off load crude. The truck racks also load asphalt and LPG.




Tulsa, Oklahoma railyard
HEP constructed 23,500 track feet of rail storage on land situated near the railway station ofHF Sinclair's Tulsa Oklahoma.refinery. HEP leases a portion of this land from BNSF Railway Company and subleases this land to HFC.HF Sinclair. HEP leases the track to HFC,HF Sinclair, and HEP is receiving reimbursement from HFCHF Sinclair for the construction costs over the 25-year term of the lease.


Kansas City terminal
The Kansas City Terminal receives refined products via truck and a Magellan Midstream Partners, LLC (“MMPL”) pipeline from the MMPL Kansas City Terminal. Refined products received at this terminal are sold locally via a truck rack.

Carrollton terminal
The Carrollton Terminal loading rack facility consists of a light refined products truck rack fed from the five tanks at the Carrollton Tank Farm. These racks load refined products onto tanker trucks for delivery to markets in surrounding areas.

Montrose terminal
The Montrose Terminal loading rack facility consists of a light refined products truck rack fed from the six tanks at the Montrose Tank Farm. These racks load refined products onto tanker trucks for delivery to markets in surrounding areas.

Southwest Region


Abilene, Texas terminal
This terminal receives refined products from Delek's Big Spring refinery, which accounted for all of its volumes in 2017.2022. Refined products received at this terminal are sold locally via a truck rack or pumped over a 2-mile pipeline to Dyess Air Force Base. Delek is the only customer at this terminal.


Artesia, New Mexico facility truck rack
The truck rack at HFC'sHF Sinclair's Navajo refinery Artesia facility loads light refined product produced at the Navajo refinery onto tanker trucks for delivery to markets in the surrounding area. HFCHF Sinclair is the only customer of this truck rack.


Artesia, New Mexico railyard
HEP constructed 8,300 track feet of rail storage on land situated near the railway station of Artesia, New Mexico. HEP leases this land from BNSF Railway Company and subleases the land to HFC.HF Sinclair. HEP leases the track to HFC,HF Sinclair, and HEP is receiving reimbursement from HFCHF Sinclair for the construction costs over the 25 year25-year term of the lease.


Lovington, New Mexico facility asphalt truck rack
The asphalt loading rack facility at HFC'sHF Sinclair's Navajo refinery Lovington facility loads asphalt produced at the Navajo refinery into tanker trucks. HFCHF Sinclair is the only customer of this truck rack.


Moriarty, New Mexico terminal
We receive light refined product at this terminal from the Navajo refinery Artesia facility through our pipelines. Refined product received at this terminal is sold locally, via the truck rack. HFCHF Sinclair is the only customer at this terminal, and there are no competing terminals in Moriarty, New Mexico.


Orla, Texas tank farm
The Orla tank farm receives refined product from Delek's Big Spring refinery. Refined product received at the tank farm is delivered into our Orla to El Paso pipeline segment (described above). Delek

Orla, Texas terminal
This terminal receives diesel from HF Sinclair's Navajo refinery in Artesia, New Mexico and delivers diesel to the truck rack at the facility. HF Sinclair is the only customer at this tank farm.truck rack.

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Tankage at HFCHF Sinclair refinery facilities
At HFC'sHF Sinclair's Artesia and Lovington refinery facilities, HEP owns crude tankage that supports the refineries in their production of petroleum products. HFCHF Sinclair is the only customer utilizing these tanks.

Tucson, Arizona terminal
We own 100% of the improvements and lease a portion of the underlying ground at this terminal. Refined product received at the Tucson terminal originate from HFC's Navajo refinery Artesia facility and is transported, on our pipelines, to HFC's El Paso terminal where it connects to Kinder Morgan Energy Partners, L.P.'s East system pipeline that delivers into the Tucson terminal. Refined product received at this terminal is sold locally, via the truck rack. The lease on a portion of the underlying ground at this terminal expired in February 2018, and we are evaluating our options for this terminal.


Wichita Falls, Texas terminal
This terminal receives refined product from Delek's Big Spring refinery, which accounted for all of its volumes in 2017.2022. Refined product received at this terminal is sold via a truck rack or shipped via pipeline connections to Delek’s terminal in Duncan, Oklahoma and also to NuStar Energy L.P.’s Southlake Pipeline. Delek is the only customer at this terminal.


Northwest Region


Frontier Anshutz and Frontier Arepi Stations
Tankage at these two terminals on the Frontier Pipeline in Wyoming is used to store various grades of crude shipped on the Frontier Pipeline.

Mountain Home, Idaho terminal
We receive jet fuel from third parties at this terminal that is transported on Andeavor LogisticsMPLX LP's Salt Lake City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal through our 13-mile pipeline to the United States Air Force base outside of Mountain Home. Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air base. We are paid a single fee, from the Defense Energy Support Center, for injecting, storing, testing and transporting jet fuel at this terminal.




Spokane, Washington Terminal
This terminal is connected to the Woods Cross refinery via a Andeavor LogisticsMPLX LP's common carrier pipeline. The Spokane terminal is also supplied by rail and truck. Refined product received at this terminal is sold locally, via the truck rack. We have several major customers at this terminal.


Woods Cross, Utah Crude Tankage at HFC refinery facilities
At HFC'sHF Sinclair's Woods Cross refinery facility, HEP owns crude tankage that supports the refinery in its production of petroleum products. HFCHF Sinclair is the only customer utilizing these tanks.


UNEV terminals
UNEV owns two terminals, located in Cedar City, Utah and North Las Vegas, Nevada, that receive product through the UNEV Pipeline, originating in Woods Cross, Utah. Refined product received at these terminals is sold locally.


Woods Cross, Utah facility truck rack
The truck rack at the Woods Cross facility loads light refined product produced at HFC'sHF Sinclair's Woods Cross refinery onto tanker trucks for delivery to markets in the surrounding area. HFCHF Sinclair is the only customer of this truck rack.


Denver Products Terminal
The truck rack at the Denver Products Terminal loads light refined product delivered from multiple pipelines onto tanker trucks for delivery to markets in the surrounding area.

Sinclair Products Terminal
The truck rack at the Sinclair Products Terminal loads light refined product produced at the HF Sinclair Parco refinery onto tanker trucks for delivery to markets in the surrounding area.

Casper Products Terminal
The truck rack at the Casper Products Terminal loads light refined product produced at the HF Sinclair Casper refinery onto tanker trucks for delivery to markets in the surrounding area.

Casper Crude Terminal
The truck unloading facility in Casper receives local gathered crude via truck deliveries into tankage where it is then delivered to either the HF Sinclair Parco or Casper refineries.

Guernsey Crude Terminal
The crude facility in Guernsey receives crude from local gathering systems, the Plains system and others, where it is stored and then delivered to either the HF Sinclair Parco or Casper refineries.

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Sinclair Crude Terminal
The truck unloading facility in Sinclair receives local gathered crude via truck deliveries into tankage where it is then delivered to the HF Sinclair Parco refinery.

Parco S-Tank farm
The tank farm at Parco is used for various purposes including seasonal product storage, refinery turnaround support, and intermediate product storage. It can receive product from either the HF Sinclair Parco refinery or from the Salvation pipeline.

Burley Terminal
The truck rack at the Burley Products Terminal loads light refined product delivered from MPLX LP's pipeline onto tanker trucks for delivery to markets in the surrounding area.

Boise Terminal
The truck rack at the Boise Products Terminal loads light refined product delivered from MPLX LP's pipeline onto tanker trucks for delivery to markets in the surrounding area.

Pioneer North Salt Lake Terminal
The truck rack at the North Salt Lake Terminal, which is owned by Pioneer Investments Corp., loads light refined product delivered from the Pioneer Pipeline onto tanker trucks for delivery to markets in the surrounding area. It can receive product from either the HF Sinclair Parco or Casper refineries through the Pioneer Pipeline. HEP owns a 49.995% interest in Pioneer Investments Corp.
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The following table outlines the locations of our majority-owned terminals and their storage capacities, number of tanks, supply source, and mode of delivery:delivery as of December 31, 2022:
Terminal LocationStorage
Capacity
(barrels)		Number
of
Tanks		Supply SourceMode of Delivery
Moriarty, NM196,000 8PipelineTruck
Mountain Home, ID (1)
122,000 4PipelinePipeline
Spokane, WA468,000 34Pipeline/RailTruck
Abilene, TX147,000 6PipelineTruck/Pipeline
Wichita Falls, TX238,000 12PipelineTruck/Pipeline
Las Vegas, NV442,000 12Pipeline/TruckTruck
Cedar City, UT205,000 7Pipeline/Rail/TruckTruck
Orla tank farm178,000 6PipelinePipeline
Orla, TX45,000 1PipelineTruck
El Dorado, KS crude tankage1,044,000 11PipelinePipeline
Stations along the SLC and Frontier pipelines383,000 7PipelinePipeline
Stations in the Texas, New Mexico crude system447,000 14PipelinePipeline
Catoosa, OK lube terminal74,000 6Truck/RailTruck
Bairoil, WY100,000 2PipelinePipeline
Boise Terminal440,000 16Pipeline/TruckTruck
Burley Terminal164,000 8Pipeline/TruckTruck
Carrollton Terminal327,000 5Pipeline/TruckTruck/Pipeline
Casper, WY1,269,000 13Pipeline/TruckTruck/Pipeline
Denver Terminal917,000 19Rail/Truck/PipelineTruck/Pipeline
Montrose, IA173,000 6Pipeline/TruckTruck
Guernsey, WY416,000 4PipelinePipeline
Kansas City Terminal345,000 7Pipeline/TruckTruck
Sand Draw, WY25,000 2Pipeline/TruckPipeline
Sinclair, WY419,000 7PipelinePipeline
Artesia facility railyardN/AN/ARailRail
Artesia facility truck rackN/AN/ARefineryTruck
Lovington facility asphalt truck rackN/AN/ARefineryTruck
Woods Cross facility truck rackN/AN/ARefineryTruck
Tulsa West facility truck and rail rackN/AN/ARefineryTruck/Rail/Pipeline
Tulsa East facility truck and rail racksN/AN/ARefineryTruck/Rail/Pipeline
Tulsa facility railyardN/AN/ARailRail
Cheyenne facility truck racks (2)
N/AN/ARefineryTruck
El Dorado facility truck racksN/AN/ARefineryTruck
Total8,584,000 
(1)Handles only jet fuel.
(2)Inactive


Terminal Location 
Storage
Capacity
(barrels)
 
Number
of
Tanks
 Supply Source Mode of Delivery
Moriarty, NM 211,000
 9 Pipeline Truck
Bloomfield, NM (1)
 203,000
 7 Pipeline Truck
Tucson, AZ(2)
 186,000
 9 Pipeline Truck
Mountain Home, ID(3)
 122,000
 4 Pipeline Pipeline
Spokane, WA 384,000
 28 Pipeline/Rail Truck
Abilene, TX 157,000
 6 Pipeline Truck/Pipeline
Wichita Falls, TX 220,000
 11 Pipeline Truck/Pipeline
Las Vegas, NV 378,000
 12 Pipeline/Truck Truck
Cedar City, UT 235,000
 7 Pipeline/Rail/Truck Truck
Orla tank farm 129,000
 5 Pipeline Pipeline
El Dorado, KS crude tankage 1,150,000
 11 Pipeline Pipeline
Frontier Anschutz Station 260,000
 3 Pipeline Pipeline
Frontier Arepi Station 100,000
 3 Pipeline Pipeline
SLC North Salt Lake Station 10,000
 1 Pipeline Pipeline
Artesia facility railyard N/A
 N/A Rail Rail
Artesia facility truck rack N/A
 N/A Refinery Truck
Lovington facility asphalt truck rack N/A
 N/A Refinery Truck
Woods Cross facility truck rack N/A
 N/A Refinery Truck/Pipeline
Tulsa West facility truck and rail rack N/A
 N/A Refinery Truck/Rail/Pipeline
Tulsa East facility truck and rail racks N/A
 N/A Refinery Truck/Rail/Pipeline
Tulsa facility railyard N/A
 N/A Rail Rail
Cheyenne facility truck racks N/A
 N/A Refinery Truck
El Dorado facility truck racks N/A
 N/A Refinery Truck
Total 3,745,000
      
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(1)Inactive
(2)The underlying ground at the Tucson terminal is leased.
(3)Handles only jet fuel.




The following table outlines the locations of our refinery tankage, storage capacity, tankage type and number of tanks as of December 31, 2022:
Refinery and Renewable Diesel Facility LocationStorage
Capacity
(barrels)		Tankage TypeNumber
of
Tanks
Artesia , NM366,000 Crude oil and refined product8
Lovington, NM291,000 Crude oil2
Woods Cross, UT168,000 Crude oil3
Tulsa, OK3,828,000 Crude oil and refined product58
Cheyenne, WY452,000 Crude oil and refined product9
El Dorado, KS4,105,000 Refined and intermediate product88
Total9,210,000 
Refinery Location 
Storage
Capacity
(barrels)
 Tankage Type 
Number
of
Tanks
Artesia , NM 180,000
 Crude oil 2
Lovington, NM 309,000
 Crude oil 2
Woods Cross, UT 190,000
 Crude oil 3
Tulsa, OK 3,727,000
 Crude oil and refined product 61
Cheyenne, WY 1,915,000
 Crude oil and refined product 54
El Dorado, KS 3,877,000
 Refined and intermediate product 90
Total 10,198,000
    




CONTROL OPERATIONS OF PIPELINES AND TERMINALS


All of our pipelines are operated via geosynchronous satellite, microwave and radio systems from our central control room located in Artesia, New Mexico. We also monitor activity at our terminals from this control room. The control center operates with state-of-the-art Supervisory Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points on the pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces our requirement for full-time on-site personnel at most of these locations.


REFINERY PROCESSING UNITS


Our refinery processing units are integrated in HFC'sHF Sinclair's El Dorado, Kansas refinery and HFC'sHF Sinclair's Woods Cross, Utah refinery and are used to support their daily operations, which chemically transform crude oil into various petroleum products, including gasoline, diesel, LPGs and asphalt.


HFC isHF Sinclair has committed to supply these units with a minimum feedstock throughput for each calendercalendar quarter. HEP has committed that these units yield a certain level of petroleum product. The initial terms for the refinery processing units at HFC'sHF Sinclair's El Dorado and Woods Cross refineries extend through 2030 and 2031, respectively.


The El Dorado units were first operational in the third and fourth quarters of 2015 and the Woods Cross units were first operational in the second quarter of 2016. These units operate on a daily basis until they are taken down for large-scale maintenance, which can be every two to four years and could last from two to four weeks. During this maintenance period (turnaround), the minimum feedstock throughput is adjusted so that HFCHF Sinclair is not penalized for HEP's maintenance requirements.


HEP's revenue is primarily generated from the minimum throughput commitment,commitments, and HEP charges a tolling fee per barrel or thousand standard cubic feet of feedstock throughput. The tolling fee is meant to provide HEP with revenue that surpasses the amount of its expected operating costs, which include natural gas and maintenance. On any calendar month where the cost of natural gas exceeds what is included in the tolling fee, HEP will charge HFCHF Sinclair for recovery of this additional cost. Additionally, if turnaround costs are more than expected after the first turnaround for each unit, the tolling fee will be permanently adjusted, one time, to recover these costs.


Our refinery processing units are managed by refinery;refinery personnel seconded from HF Sinclair; significant assets are grouped accordingly and described below.


El Dorado Refinery


Naphtha Fractionation Unit - El Dorado, Kansas refinery facility
The feedstock used by the naphtha fractionation unit is desulfurized naphtha, which is produced by the refinery earlier in the refining process. Desulfurized naphtha is a key component in gasoline, and this unit is used to reduce the level of benzene


precursors. This allows the resulting product to be processed further to produce gasoline that meets regulatory requirements. The unit's feedstock capacity is 50,000 bpd of desulfurized naphtha.


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Hydrogen Generation Unit - El Dorado, Kansas refinery facility
The hydrogen unit primarily uses natural gas as a feedstock to produce hydrogen gas that is used in HFC'sHF Sinclair's operation of its El Dorado, Kansas refinery. This feedstock is supplied from purchased natural gas. The hydrogen unit's natural gas feedstock capacity is 6,100 thousand standard cubic feet per day.


Woods Cross Refinery


Crude Unit - Woods Cross, Utah refinery facility
The crude unit is comprised of several components, primarily an atmospheric distillation tower, a desalter and heat exchangers, together referred to as the crude unit. The crude unit uses black wax and other crudes as feedstock and is the first step in the refining process to separate crude into refined products. This process is accomplished by heating the crude until it is distilled into various intermediate streams. These intermediate streams are further refined downstream of the crude unit. The initial rejection of major contaminants is also performed by the crude unit. Its feedstock capacity is 15,000 bpd of crude oil.


Fluid Catalytic Cracking Unit - Woods Cross, Utah refinery facility
The fluid catalytic cracking unit ("FCC"(“FCC”) is used to convert the high-boiling, high-molecular weight hydrocarbon fractions of crude oil to more valuable products like gasoline, diesel and LPGs. This conversion is performed by the cracking of petroleum hydrocarbons achieved from extremely high temperatures and fluidized catalyst. The FCC's capacity is 8,000 bpd of atmospheric tower bottoms from the crude unit, discussed above, and gas oil.


Polymerization Unit - Woods Cross, Utah refinery facility
The polymerization unit uses the LPGs, propylene and butylene, from the FCC unit and polymerizes them into high octane gasoline blendstock using heat and catalysts. This gasoline blendstock is combined with other blendstocks in the refinery to make finished gasoline. The polymerization unit's feedstock capacity is 2,500 bpd.
ACQUISITIONS

OsageINVESTMENT IN JOINT VENTURE
On February 22, 2016, HFC obtained a 50% membership interest in Osage Pipe Line Company,October 2, 2019, HEP Cushing LLC (“Osage”) in a non-monetary exchange for a 20-year terminalling services agreement, whereby, a subsidiary of Magellan will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Osage is the owner of the Osage pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. The Osage pipeline is the primary pipeline that supplies HFC's El Dorado Refinery with crude oil.

Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we agreed to build two connections on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. These connections were in service in the fourth quarter of 2017. Effective upon the closing of this exchange, we are the named operator of the Osage pipeline and transitioned into that role on September 1, 2016.

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

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



Woods Cross Operating
Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”HEP Cushing”), a wholly owned subsidiary of HFC, which ownsHEP, and Plains Marketing, L.P., a wholly owned subsidiary of Plains, formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for (i) the newly constructed atmospheric distillation tower, FCC,development, construction, ownership and polymerization unit locatedoperation of a new 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that will connect the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HF Sinclair 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 HFC’s Woods Cross refinery, for cash considerationthe end of $278 million. The consideration was funded with approximately $103 million in proceeds from a private placementthe third quarter of 3,420,000 common units representing limited partnership interests at a price of $30.18 per common unit with the balance funded with borrowings under our credit facility. In connection with this transaction, we2021. Long-term commercial agreements have been entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC that provide minimum annualized revenuesto support the Cushing Connect Joint Venture assets.

The Cushing Connect Joint Venture contracted with an affiliate of $57 million asHEP to manage the construction and operation of the acquisition date.

SLCCushing Connect Pipeline and Frontier Aspenwith an affiliate of Plains to manage the operation of the Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment was generally shared equally among HEP and Plains. However, we were solely responsible for any Cushing Connect Pipeline construction costs that exceeded the budget by more than 10%. HEP's share of the cost of the Cushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline construction costs were approximately $74 million, including approximately $5 million of Cushing Connect Pipeline construction costs that exceeded the budget by more than 10% borne solely by HEP.
On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline LLC ("SLC Pipeline")
The investment above and the remaining 50% interest in Frontier Aspen LLC ("Frontier Aspen") from subsidiaries of Plains, for total consideration of $250 million. Prior to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a result of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.

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

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

The acquisitions above and their basis of presentation areis described further in Notes 1 and 2Note 3 in notes to consolidated financial statements of HEP, and the descriptionsdescription in Notes 1 and 2 areNote 3 is incorporated herein by reference.


AGREEMENTS WITH HFC AND DELEKHF SINCLAIR


We serve HFC'sHF Sinclair's refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from 20192023 to 2036.2037. Under these agreements, HFCHF Sinclair agrees to transport, store, and process throughput volumes of refined products, 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. As of December 31, 2017, these2022, our agreements with HFC requireHF Sinclair required minimum annualized payments to us of $324$453 million.
If HFCHF Sinclair fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.
We have a pipelines and terminals agreement with Delek expiring in 2020 under which Delek has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that also is subject to annual tariff rate adjustments. We also have a capacity lease agreement under which we lease Delek space on our Orla to El Paso pipeline for the shipment of refined product. The terms under this lease agreement expire beginning in 2018 through 2022. As of December 31, 2017, these agreements with Delek require minimum annualized payments to us of $33 million.
A significant reduction in revenues under these agreements could have a material adverse effect on our results of operations.
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Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right after we have made efforts to mitigate their effects to negotiate a monthly surcharge on HFCHF Sinclair for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover HFC’sHF Sinclair’s pro rata portion of the cost of complying with these laws or regulations including a reasonable rate of return. In such instances, we will negotiate in good faith with HFCHF Sinclair to agree on the level of the monthly surcharge or increased tariff rate.
For additional information regarding our significant customers, see Note 9On 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 noteseach case effective January 1, 2021: (1) a ten-year lease with two five-year renewal option periods for HFC’s (and now HF Sinclair’s) use of certain HEP tank and rack assets in the Cheyenne Refinery to consolidated financial statementsfacilitate renewable diesel production with an annual lease payment of HEP.


approximately $5 million, (2) a five-year contango service fee arrangement that will utilize HEP tank assets inside the Cheyenne Refinery where HFC (and now HF Sinclair) will pay a base tariff to HEP for available crude oil storage and HFC (and now HF Sinclair) and HEP will split any profits generated on crude oil contango opportunities and (3) HFC paid a $10 million one-time cash payment to HEP for the termination of the existing minimum volume commitment.
Omnibus Agreement
Under certain provisions of an omnibus agreement we have with HFCHF Sinclair (the “Omnibus Agreement”), we pay HFCHF Sinclair an annual administrative fee, ($2.5currently $5.0 million, in 2017) for the provision by HFCHF Sinclair or its affiliates of various general and administrative services to us. This fee includes expenses incurred by HFCHF Sinclair to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. ThisIn connection with the HEP Transaction, we paid HF Sinclair a temporary monthly fee does not includeof $62,500 through November 30, 2022, relating to transition services provided to HEP by HF Sinclair. Neither the annual administrative fee nor the temporary monthly fee includes the salaries of personnel employed by HFCHF Sinclair who perform services for us on behalf of HLS or the cost of their employee benefits, which are separately charged to us by HFC.HF Sinclair. We also reimburse HFCHF Sinclair and its affiliates for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, directors’ compensation, and registrar and transfer agent fees.


Under HLS’s secondment agreement with HFCHF Sinclair (the “Secondment Agreement”), certain employees of HFCHF Sinclair are seconded to HLS, our ultimate general partner, to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFCHF Sinclair for its prorated portion of the wages, benefits, and other costs of these employees for our benefit.
COMPETITION
As a result of our physical integration with HF Sinclair’s refineries, our contractual relationship with HF Sinclair under the Omnibus Agreement and the HF Sinclair pipelines and terminals, tankage and throughput agreements, we believe that we will not face significant competition for barrels of crude oil transported to or refined products transported from HF Sinclair’s refineries, particularly during the terms of our long-term transportation agreements with HF Sinclair expiring between 2023 and 2037.
However, we do face competition from other pipelines that may be able to supply the end-user markets of HF Sinclair or other customers with refined products on a more competitive basis. Additionally, if HF Sinclair’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers, decreased demand for refined products or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.
The petroleum refining business is highly competitive. Among HF Sinclair’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. HF Sinclair competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.
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Our refined product terminals compete with other independent terminal operators as well as integrated oil companies based on terminal location, price, versatility and services provided. Our competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms. Historically, the significant majority of the throughput at our terminal facilities has come from HF Sinclair.
GOVERNMENTAL REGULATION
Safety and Maintenance
Many of our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the Department of Transportation. PHMSA has promulgated regulations governing, among other things, maximum operating pressures, pipeline patrols and leak surveys, control room management, and emergency procedures, as well as other matters intended to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas.
In addition, many states have adopted regulations, similar to, or which go above and beyond, existing PHMSA regulations, for certain intrastate pipelines. For example, Texas has developed regulatory programs that largely parallel the federal regulatory scheme and impose additional requirements for certain pipelines. Furthermore, other related programs, such as the EPA’s Risk Management Program and the Occupational Safety and Health Administration’s Process Safety Management standard apply to some of our terminals and associated facilities.
We perform preventive and normal maintenance on all of our pipeline and terminal systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by regulations. Corrosion inhibitors, external coatings and impressed current cathodic protection systems are used to protect against internal and external corrosion. We regularly monitor, test and record the effectiveness of these corrosion-control systems. We monitor the structural integrity of covered segments of our pipeline systems through a program of periodic internal inspections using electronic “smart pigs”, hydrostatic testing, and other measures. We follow these inspections with a review of the data, and we make repairs as necessary to maintain the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other appropriate integrity testing methods. This approach is intended to allow the pipelines that have the greatest risk potential to receive the highest priority in being scheduled for inspections or pressure tests for integrity. Nonetheless, the adoption of new or amended regulations or the reinterpretation of existing laws and regulations by PHMSA or states that result in more stringent or costly pipeline integrity management or safety standards could possibly have a substantial effect on us and similarly situated midstream operators.
Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill response exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements.
At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.
Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals participate in a comprehensive environmental management program to assure compliance with applicable air, solid waste and wastewater regulations.
For further information on pipeline safety and regulatory requirements related to maintenance, see our risk factor “Our operations are subject to evolving federal, state and local laws, regulations and permit/authorization requirements regarding our business, capital projects, environmental protection, health, operational safety and product quality. Potential liabilities arising from these laws, regulations and requirements could affect our operations and have a material adverse effect on our business.” under Item 1A – “Risk Factors.”
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FERC Regulation - Liquids Pipelines
Some of our existing refined products and crude oil pipelines provide interstate transportation services subject to regulation by the FERC pursuant to the Interstate Commerce Act (the “ICA”). The ICA requires that the rates charged by these pipelines (referred to as “interstate liquids pipelines”) must be just and reasonable. The ICA also prohibits interstate liquids pipelines from providing services in a manner that unduly discriminates against or confers undue preference upon any shipper. The ICA permits interested persons to challenge newly proposed or changed rates or rules and authorizes the FERC to suspend the effectiveness of such proposed rates or rules for a period of up to seven months, during which the FERC may investigate whether the proposed rate or rules are just and reasonable. Upon completion of an investigation, the FERC may require the interstate liquids pipeline carrier to refund the revenues collected during the pendency of the investigation that are in excess of the amount the FERC determines to be just and reasonable, together with interest. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order an interstate liquids pipeline to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations (including interest) for damages sustained during the two years prior to the filing of a complaint.

As a general matter, interstate liquids pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index that FERC reviews every five years. Cost-of-service ratemaking, market-based rates, and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates. When an interstate liquids pipeline adjusts its rates using the index methodology, shippers may challenge rate increases made within the ceiling levels. The FERC’s regulations provide that a protest against an index rate increase must allege “reasonable grounds” that the index rate increase is “so substantially in excess of the actual cost increases incurred by the carrier that the rate is unjust and unreasonable.”

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 were permitted to adjust their indexed ceilings annually by Producer Price Index plus 0.78%. FERC received requests for rehearing of its December 17, 2020 order, and on January 20, 2022, FERC revised the index level used to determine the annual changes to interstate oil pipeline rate ceilings to Producer Price Index minus 0.21%. The order required recalculation of the July 1, 2021 index ceilings to be effective as of March 1, 2022.

State Regulation - Liquids Pipelines

While the FERC regulates the rates for interstate shipments on our interstate liquids pipelines, the New Mexico Public Regulation Commission regulates the rates for intrastate shipments on our pipelines in New Mexico, the Texas Railroad Commission regulates the rates for intrastate shipments on our pipelines in Texas and the Oklahoma Corporation Commission regulates the rates for intrastate shipments on our pipelines in Oklahoma. Generally, these state agencies have not investigated the rates or practices of intrastate pipelines subject to their jurisdiction in the absence of shipper complaints.

Environmental Regulation and Remediation

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 potential discharge of materials into the environment, or otherwise relating to the protection of human health and the environment and natural resources, including climate change. These laws and regulations may require us to obtain permits for our operations or result in the imposition of strict requirements relating to air emissions, and characteristics and composition of gasoline and diesel fuels, biodiversity, wastewater discharges, waste management, process safety and risk management, spill planning and prevention and the remediation of spills, leaks and other contamination. As with the industry generally, compliance with existing, changing, and new laws, regulations, interpretations and guidance increases our overall cost of business, including our capital costs to construct, maintain, upgrade and operate equipment and facilities. These laws and regulations affect our operations, maintenance, capital expenditures and net income, as well as those of our competitors. These existing and any new 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, and injunctions, construction bans or delays; delays in the permitting, development or expansion of projects; limitations or prohibitions on certain operations; and reputational harm. In addition, many environmental laws contain citizen suit provisions, allowing environmental groups to bring suits to enforce compliance with environmental laws. Environmental groups frequently challenge pipeline infrastructure projects. Moreover, a major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured or is not fully insured, subject us to substantial expense, including the cost of remediation and restoration of any damaged natural resources, 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.

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Some environmental laws impose liability without regard to fault or the legality
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of the original act on certain classes of persons that contributed to the releases of hazardous substances or petroleum hydrocarbon substances into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes.

There are environmental remediation projects in progress, including assessment and monitoring activities, that relate to certain assets acquired from HF Sinclair. Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HF Sinclair, HF Sinclair 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 HF Sinclair and occurring or existing prior to the date of such transfers.

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

At December 31, 2022, we have an accrual of $19.5 million that relates to environmental clean-up projects for which we have assumed liability,including accrued environmental liabilities assumed in the Sinclair Transportation acquisition that have preliminarily been fair valued at $14.7 million as of the acquisition date, or for which the indemnity provided for by HF Sinclair has expired. There are environmental remediation projects in progress, including assessment and monitoring activities, that relate to certain assets acquired from HF Sinclair. Certain of these projects were underway prior to our purchase, are covered under the HF Sinclair environmental indemnification discussed above, and represent liabilities retained by HF Sinclair.

On July 8, 2022, the Osage pipeline, which carries crude oil from Cushing, Oklahoma to El Dorado, Kansas, suffered a release of crude oil. Our equity in earnings (loss) of equity method investments was reduced in the year ended December 31, 2022 by $17.6 million for our 50% share of incurred and estimated environmental remediation and recovery expenses associated with the release, net of our share of insurance proceeds received to date of $3.0 million. We expect Osage will receive additional insurance recoveries, which will be recorded as they are received. If our insurance policy pays out in full, our share of the remaining insurance coverage is expected to be $9.5 million. The pipeline resumed operations in the third quarter of 2022 and remediation efforts are underway.

We may experience future releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although we maintain an extensive inspection and audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets have the potential to substantially affect our business.
CAPITAL REQUIREMENTS
Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. “Maintenance capital expenditures” represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. “Expansion capital expenditures” represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.


Each year the board of directors of HLS, our ultimate general partner, approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year's capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2018Our current 2023 capital budgetforecast is comprised of $8approximately $25 million to $35 million for maintenance capital expenditures and $40$5 to $10 million for expansion capital expenditures. We expect the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks,expenditures and enhanced blending capabilities at our racks.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.
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We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects, will be funded with cash generated by operations,operations. We expect that, to the sale ofextent necessary, we can raise additional limited partner common units, the issuance offunds from time to time through equity or debt securities and advances under our senior secured revolving credit facility (the “Credit Agreement”), or a combination thereof. With volatility and uncertainty at timesfinancings in the creditpublic 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 additionalprivate capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.markets.
Under the terms of the transaction to acquire HFC's 75% interest in UNEV, we issued to a subsidiary of HFC (now HF Sinclair) 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% interest in our share75% of annual UNEV earnings before interest, income taxes, depreciation and amortization above $30$40 million beginning July 1, 2016,2015, 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.
SAFETY AND MAINTENANCEHUMAN CAPITAL
Many of our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the Department of Transportation. PHMSA has promulgated regulations governing, among other things, maximum operating


pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas.
In addition, many states have adopted regulations, similar to existing PHMSA regulations, for certain intrastate pipelines. For example, Texas has developed regulatory programs that largely parallel the federal regulatory scheme and impose additional requirements for certain pipelines.Our People
We perform preventive and normal maintenance on allare managed by HLS, our ultimate general partner. HLS is a subsidiary of our pipeline and terminal systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by regulations. We inject corrosion inhibitors into our mainlines to help control internal corrosion. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems. We monitor the structural integrity of covered segments of our pipeline systems through a program of periodic internal inspections using both “dent pigs” and electronic “smart pigs”, as well as hydrostatic testing that conforms to federal standards. We follow these inspections with a review of the data, and we make repairs as necessary to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. We believe this approach will allow the pipelines that have the greatest risk potential to receive the highest priority in being scheduled for inspections or pressure tests for integrity. Nonetheless, the adoption of new or amended regulations or the reinterpretation of existing laws and regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could possibly have a substantial effect on us and similarly situated midstream operators.
Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. Also they participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements.
At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.

Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals are subject to participation in a comprehensive environmental management program to assure compliance with applicable air, solid waste, and wastewater regulations.
COMPETITION
As a result of our physical integration with HFC’s refineries, our contractual relationship with HFC under the Omnibus Agreement and the HFC pipelines and terminals, tankage and throughput agreements, we believe that we will not face significant competition for barrels of crude oil transported to or refined products transported from HFC’s refineries, particularly during the terms of our long-term transportation agreements with HFC expiring between 2019 and 2036. Additionally, under our throughput agreement with Delek expiring in 2020, we believe that we will not face significant competition for those barrels of refined products we transport from Delek’s Big Spring refinery.
However, we do face competition from other pipelines that may be able to supply the end-user markets of HFC or Delek with refined products on a more competitive basis. Additionally, if HFC’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.
HF Sinclair. The petroleum refining business is highly competitive. Among HFC’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. HFC competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.


Our refined product terminals compete with other independent terminal operators as well as integrated oil companies based on terminal location, price, versatility andemployees providing services provided. Our competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms. Historically, the significant majority of the throughput at our terminal facilities has come from HFC.
RATE REGULATION
Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and not unduly discriminatory. The Interstate Commerce Act permits challenges to rates that are already on file and in effect by complaint. A successful challenge under a complaint may result in the complainant obtaining damages or reparations for up to two years prior to the date the complaint was filed. The Interstate Commerce Act also permits challenges to a proposed new or changed rate by a protest. A successful challenge under a protest may result in the protestant obtaining refunds or reparations from the date the proposed new or changed rate becomes effective. In either challenge process, the third party must be able to show it has a substantial economic interest in those rates to proceed. The FERC generally has not investigated interstate rates on its own initiative but will likely become a party to any proceedings when the rates receive either a complaint or a protest. However, the FERC is not prohibited from bringing an interstate rate under investigation without a third-party intervention.

While the FERC regulates the rates for interstate shipments on our refined product pipelines, the New Mexico Public Regulation Commission regulates the rates for intrastate shipments in New Mexico, the Texas Railroad Commission regulates the rates for intrastate shipments in Texas, the Oklahoma Corporation Commission regulates the rates for intrastate shipments in Oklahoma and the Idaho Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State commissions have generally not been aggressive in regulating common carrier pipelines and generally have not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints, and we do not believe the intrastate tariffs now in effect are likely to be challenged. However, a state regulatory commission could investigate our rates if such a challenge were filed.
ENVIRONMENTAL REGULATION AND REMEDIATION
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 and natural resources. These laws and regulations may require us to obtain permits for our operations or result in the imposition of strict requirements relating to air emissions, biodiversity, wastewater discharges, waste management, or the remediation of contamination. 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 operations, maintenance, capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. In addition, many environmental laws contain citizen suit provisions, allowing environmental groups to bring suits to enforce compliance with environmental laws. Environmental groups frequently challenge pipeline infrastructure projects. Moreover, 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.
Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Some environmental laws impose liability without regard to fault or the legality of the original act on certain classes of persons that contributed to the releases of hazardous substances or petroleum hydrocarbon substances into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements.


Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.
We have an environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations.
There are environmental remediation projects that are currently in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At December 31, 2017, we have an accrual of $6.5 million that relates to environmental clean-up projects for which we have assumed liability or for which the indemnity provided for by HFC has expired or will expire. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.
We may experience future releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although we maintain an extensive inspection and audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets have the potential to substantially affect our business.
EMPLOYEES
Neither we nor our general partner has employees. Direct support for our operations iseither provided by HLS, which utilizes 269 people employed by HFC dedicatedHF Sinclair to performingperform services for us. We reimburse HFC for direct expenses that HFCus, or its affiliates incurs onseconded to us by subsidiaries of HF Sinclair, as neither we nor our behalf for theseultimate general partner have any employees. HFC considers its employee relations to be good.
Under the Secondment Agreement agreement with HFC,HF Sinclair, certain employees of HFCHF Sinclair are seconded to HLS, our ultimate general partner, to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFCHF Sinclair for its prorated portion of the wages, benefits, and other costs of these employees for our benefit. In addition, as more fully described under Part III, Item 11. Executive Compensation, certain executive officers of HLS are also executive officers of HF Sinclair and devote as much of their professional time as necessary to oversee the management our business and affairs.
The “One HF Sinclair Culture” focuses on five key values – safety, integrity, teamwork, ownership and inclusion. These values influence decisions, shape behaviors and provide the opportunity for employees to thrive. Safety is our first priority. We care about our people and have implemented policies and procedures designed to help them return home safely every day. We focus on integrity and doing the right thing. We champion a culture of teamwork and ownership by supporting each other and empowering employees to take action where they see a need or opportunity. Inclusion reflects our desire to foster a work environment in which employees feel valued and included in decisions, opportunities and challenges.

As of December 31, 2022, 405 HF Sinclair employees were dedicated to our business in addition to HF Sinclair employees seconded to HLS for a portion of their time to provide services to our business as described above. From time to time, a portion of HF Sinclair’s employees that are seconded to us, are covered by collective bargaining agreements. The current collective bargaining agreements have various expiration dates between 2023 and 2026. We have experienced no material interruptions of operations due to disputes with those employees and management believes that positive working relationships exist between HF Sinclair and local unions and their members.
Oversight
As a result of our secondment arrangements with HF Sinclair, strategic oversight for human capital management is shared between the HLS Board of Directors and board committees and the HF Sinclair Board of Directors and board committees. As further discussed under Part III, Item 11. Executive Compensation, the HLS Compensation Committee determines cash and bonus compensation for HLS’s Chief Executive Officer, President or Chief Financial Officer if such officers are solely dedicated to HLS. The HF Sinclair Board of Directors and Board committees provide oversight on strategies and policies related to the human capital management of HF Sinclair employees seconded to, and shared with, HLS. The HF Sinclair Compensation Committee is responsible for periodically reviewing HF Sinclair’s strategies and policies regarding the promotion of employee diversity, equity and inclusion, talent and performance management, pay equity and employee engagement, as well as executive succession planning. The HLS Board of Directors and HF Sinclair’s Nominating, Governance and Social Responsibility Committee oversee policies and practices regarding human rights in their respective operations and supply chain. This process is designed to provide high level oversight of our strategies related to attracting, retaining and developing a workforce that aligns with our values and strategies.
Diversity & Inclusion
HLS and HF Sinclair leadership is committed to attracting, retaining and developing a highly engaged, high-performing, diverse workforce and cultivating an inclusive workplace where all employees feel valued and have a sense of belonging. Of HF Sinclair's total employees as of December 31, 2022, approximately 17% identified as female and approximately 83% identified as male. Approximately 22% of HF Sinclair's total employees identified as Hispanic or Latino, Black or African American, Asian, American Indian or Alaskan Native, Native Hawaiian or Other Pacific Islander, or as two or more races. We are also committed to hiring and retaining veterans and reservists of the U.S. armed forces, who represented approximately 5% of HF Sinclair's U.S. workforce as of December 31, 2022.
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Increasing diversity and inclusion efforts is an organizational priority for HLS and HF Sinclair. HF Sinclair has introduced diversity awareness programs focused on increasing the number of underrepresented persons in engineering roles. HF Sinclair’s university recruiting team has partnered with historically black colleges and universities to offer full-time and summer internship opportunities and various diversity and inclusion organizations at universities to sponsor and participate in events, such as the North Texas Women’s Energy Network and the National Society of Black Engineers Convention. In addition, to help foster a culture of inclusion, HF Sinclair has two employee resource groups, one focused on developing talent at HF Sinclair by fostering relationships through education, networking and leadership development opportunities and the other focused on veterans. In 2021, HF Sinclair formed an Inclusion and Diversity Working Group to develop and further implement HF Sinclair’s inclusion and diversity initiatives, to gather and report best practices related to inclusion and diversity, and to assist in developing ongoing inclusion and diversity goals and objectives.
Health & Safety
The safety of our employees, contractors and communities is an overarching priority and fundamental to our operational success. We have a comprehensive Pipeline Excellence Program that builds upon best practices and processes and is designed to advance organizational safety and performance, drive reliability and deliver strong results. Our approach allows for flexibility in unique operations and environments and provides a model for continuous improvement and fosters a strong culture of safety within our company. Pipelines are a vital component of our nation’s infrastructure, making it imperative that we safeguard our pipelines against any type of damage. We have implemented rigorous awareness and damage prevention programs that aim to educate the public and other key stakeholders and continually invest in the maintenance and integrity of our assets, including inspection and repair programs to comply with federal and state regulations.
Total Rewards & Development
We believe that the health of our company is linked to the performance and health of our people. The HF Sinclair employees that provide service to us are eligible to participate in the same comprehensive and competitive total rewards programs that are provided to employees of HF Sinclair generally. HF Sinclair’s benefit offerings are designed to support employee health, financial and emotional needs, inclusive of comprehensive coverage for health care, a competitive retirement savings benefit, vacation and holiday time and other income protection and work life benefits. HF Sinclair also provides tools to help recognize and reward employee performance consistent with the One HF Sinclair Culture.
Consistent with the HF Sinclair culture values of ownership and growth, HF Sinclair offers training, development and engagement programs to its employees that provide services to us which provide employees the opportunity to develop their career by enhancing skills and capabilities consistent with the needs of the business. Our suite of programs include: Accelerate, a curated collection of on-demand e-learning for all employees; Refine, interactive, instructor-led workshops focusing on professional development at any career level; Front Line Leadership Development, a series of leadership training for new and existing supervisors; Catalyst, a guided cohort of new leaders learning about leadership styles and executive presence; and Leading the HF Sinclair Way, a deep-dive for our senior leaders on leading through our cultural values and business objectives.
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Item 1A.Risk Factors
Item 1A.Risk Factors
Risk Factor Summary

Investing in us involves a degree of risk,risk. You should carefully consider all information in this Form 10-K, including the risks described below. Our operating results have been,Management’s Discussion & Analysis section and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should consider the following risk factors carefully together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when decidingprior to investinvesting in our common units. These risks and uncertainties include, but are not limited to, the following:

Risks Related to our Business/Industry:
•We depend on HF Sinclair for a substantial portion of our revenues. A significant reduction in those revenues or a material deterioration of HF Sinclair's financial condition could reduce our revenues materially.
•General economic conditions or, due to our lack of asset and geographic diversification, an adverse development in our businesses could materially and adversely affect our financial condition, results of operations, or cash flows.
•Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.
•A material decrease in the supply, or a material increase in the price, of crude oil or other materials available to HF Sinclair's refineries and our pipelines and terminals, and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could reduce our revenues materially.
•Competition from other pipelines that may be able to supply our shippers' customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.
•Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.
•If we are unable to complete capital projects at their expected costs or in a timely manner, incur increased maintenance or repair costs on assets, or if assumed market conditions deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.
•The COVID-19 pandemic, and actions taken in response thereto, has had and may continue to have a material adverse effect on our business.
•We may be unsuccessful in integrating the operations of acquired assets or businesses, including the Sinclair business acquired in the HEP Transaction, and in realizing the anticipated benefits of any such acquisitions.
•We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities, if our assumptions concerning population growth are inaccurate, or if an agreement cannot be reached with HF Sinclair for the acquisition of assets on which we have a right of first offer.
•We do not own all of the land on which our pipeline systems and other assets are located, which could result in disruptions to our operations. Regulatory changes related to a state’s use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects.
•Our business may suffer due to a change in the composition of our Board of Directors, the departure of any of our key senior executives or other key employees who provide services to us.
•Terrorist attacks, and the threat of terrorist attacks or vandalism, have resulted in increased costs to our business. Global hostilities may adversely impact our results of operations.
•We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications.
•We may not be able to retain existing customers or acquire new customers.
• We own certain of our systems through joint ventures, and our control of such systems is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such enterprises.

Risks Related to Government Regulation
•Our operations are subject to evolving federal, state and local laws, regulations, oversight by governmental agencies and permit/authorization requirements regarding our business, capital projects and environmental protection (including greenhouse gases and climate change protection), health, operational safety and product quality, any of which could result in potential liabilities, increased operating costs, and reduced demand for our services.

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•Increasing attention to environmental, social and governance (“ESG”) matters may adversely impact our business, financial results, stock price or price of debt securities.

Risks Related to Cybersecurity, Data Security and Privacy, Information Technology and Intellectual Property
•Cyberattacks, data security breaches, information technology system failures, network disruptions, vandalism, terrorist attacks or global hostilities or other sustained military campaigns could have a material adverse effect on our business, financial condition, results of operations or cash flows.
•Our business is subject to complex and evolving laws, security standards, and regulations and policies regarding data privacy, cybersecurity and data protection, and may be subject to additional related laws and regulations in jurisdictions in which we operate or expand. Such laws, standards and regulations could result in claims, increased cost of operations, or otherwise harm our ability to compete in the market.
Risks Related to Liquidity, Financial Instruments and Credit
•Increases in interest rates could adversely affect our business. Our leverage or volatile credit/capital markets may limit our ability to borrow funds on acceptable terms, service our indebtedness or capitalize on business opportunities.
•If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future could be impaired materially.
•We are exposed to the credit risks and certain other risks, of our or our joint ventures' key customers, vendors, and other counterparties. Adverse changes in our and/or our general partner's credit ratings and risk profile may negatively affect us.
Risks to Common Unitholders
•HF Sinclair and its affiliates may have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests or engage in limited competition with us.
•Cost reimbursements and fees due to our general partner and its affiliates for services provided are substantial. Our general partner may reduce the amount of cash in reserve available for distribution to unitholders. Even if unitholders are dissatisfied, they cannot remove our general partner without its consent. The control of our general partner may be transferred to a third party without unitholder consent.
•We may issue additional limited partner units without unitholder approval, which would dilute an existing unitholder's ownership interests. Our general partner has a limited call right that may require a unitholder to sell its common units at an undesirable time or price.
Tax Risks to Common Unitholders
•Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation. Our cash available for distribution to unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the Internal Revenue Service (“IRS”) treating us as a corporation or legislative, judicial or administrative changes, and it may also be reduced by any audit adjustments if imposed directly on the partnership.
•Even if unitholders do not receive cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
•Tax-exempt entities and non-U.S. unitholders face unique tax issues from owning our common units that may result in adverse tax consequences to them. The IRS may challenge certain tax positions, treatment methodologies or allocations, which could adversely affect the value of our common units.

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 operations. If any of the following risks were to actually occur, our business, financial condition, results of operations or treatment of unitholders could be materially and adversely affected.

The headings provided in this Item 1A. are for convenience and reference purposes only and shall not affect or limit the extent or interpretation of the risk factors.

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RISKS RELATED TO OUR BUSINESSBUSINESS/INDUSTRY

If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future could be impaired materially.

Our ability to pay quarterly distributions depends primarily on cash flow (including cash flow from operations, financial reserves and credit facilities) and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods of losses and may be unable to pay cash distributions during periods of income. Our ability to generate sufficient cash from operations is largely dependent on our ability to manage our business successfully which may also be affected by economic, financial, competitive, regulatory, and other factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, quarterly distributions may also fluctuate from quarter to quarter.


We depend on HFC and particularlyHF Sinclair (particularly its Navajo and Woods Cross refineriesrefineries) for a substantial majorityportion of our revenues; if those revenues were significantly reduced or if HFC'sHF Sinclair's financial condition materially deteriorated, there would be a material adverse effect on our results of operations.




For the year ended December 31, 2017, HFC accounted for 74%2022, HF Sinclair accounted for 70% of the revenues of our petroleum product and crude pipelines, 88%85% of the revenues of our terminals, tankage, and truck loading racks, and 100% of the revenue from our refinery processing units. We expect to continue to derive a majority of our revenues from HFCHF Sinclair for the foreseeable future. If HFCHF Sinclair satisfies only its minimum obligations under the long-term pipeline and terminal, tankage and throughput agreements that it has with us or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at HFC'sits refineries, our revenues and cash flow would decline.


Any significant reduction in production at theHF Sinclair’s Navajo refineryor Woods Cross refineries could reduce throughput in our pipelines, terminals and terminals,refinery processing units, resulting in materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2017,2022, production from theHF Sinclair's Navajo refineryand Woods Cross refineries accounted for 81%approximately 50% of the throughput volumes transported by our refined product, intermediate and crude pipelines. The NavajoOur Woods Cross refinery processing units also received 97%accounted for 70% of the throughput volumes shipped on our New Mexico intermediate pipelines. refinery processing units revenues.

Operations at any of HFC'sHF Sinclair's refineries could be partially or completely shut down, temporarily or permanently, as the result of:


•competition from other refineries and pipelines that may be able to supply the refinery's end-user markets on a more cost-effective basis;
•operational problems such as catastrophic events at the refinery, terrorist or cyberattacks, vandalism, labor difficulties, or weather, including as a result of climate change, public health crisis such as COVID-19, or government response thereto, environmental proceedings or other litigation that cause a stoppage of all or a portion of the operations at the refinery;
•planned maintenance or capital projects;
•increasingly stringent environmental laws and regulations, such as the U.S. Environmental Protection Agency's gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road usage as well as various state and federal emission requirements that may affect the refinery itself and potential future climate change regulations;
•an inability to obtain crude oil for the refinery at competitive prices; or
•a general reduction in demand for refined products in the area due to:
◦a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel;
◦higher gasoline prices due to higher crude oil costs, higher taxes or stricter environmental laws or regulations; or
◦a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation either mandating or encouraging higher fuel economy or the use of alternative fuel or otherwise. 

◦a local or national recession, public health crisis such as COVID-19, or other adverse event or economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel;
◦higher gasoline prices due to higher crude oil costs, higher taxes or stricter environmental laws or regulations; or
◦a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel efficiency, whether as a result of technological advances by manufacturers, legislation either mandating or encouraging higher fuel efficiency or the increased use of alternative fuel sources or otherwise.
For example, on June 1, 2020, HF Sinclair announced plans to permanently cease petroleum refining operations at its Cheyenne Refinery and to convert certain assets at that refinery to renewable diesel production. HF Sinclair subsequently began winding down petroleum refining operations at the Cheyenne Refinery on August 3, 2020.
The effect on us of any shutdown would depend on the length of the shutdown and the extent of the refinery operations affected by the shutdown. We have no control over the factors that may lead to a shutdown or the measures HFCHF Sinclair may take in response to a shutdown. HFCHF Sinclair makes all decisions at each of its refineries concerning levels of production, regulatory compliance, refinery turnarounds (planned shutdowns of individual process units within the refinery to perform major maintenance activities), labor relations, environmental remediation, emission control and capital expenditures and is responsible for all related costs. HFCHF Sinclair is not under no contractual obligation to us to maintain operations at its refineries.


Furthermore, HFC'sHF Sinclair's obligations under the long-term pipeline and terminal, tankage, tolling and throughput agreements with us would be temporarily suspended during the occurrence of a force majeure event that renders performance impossible with respect to an asset for at least 30 days. If such an event were to continue for a year, we or HFCHF Sinclair could terminate the agreements. The occurrence of any of these events could reduce our revenues and cash flows.


We depend
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General economic conditions may adversely affect our business, operating results and financial condition.

Economic slowdowns may have serious negative consequences for our business and operating results, because our performance is subject to domestic economic conditions and their impact on Delekdemand for crude oil and particularly its Big Spring refineryrefined products. Some of these factors include general economic conditions, unemployment, consumer debt, inflation, reductions in net worth based on declines in equity markets and residential real estate values, adverse developments in mortgage markets, taxation, energy prices, gasoline and diesel fuel prices, interest rates, consumer confidence and other macroeconomic factors. The demand for crude oil and refined and finished lubricant products can be reduced due to a portionlocal or national recession or other adverse economic condition, such as periods of increased or prolonged inflation, which results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of electric, gas/electric hybrid or hydrogen powered vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.

Political instability, actual or potential hostilities or other conflicts in oil producing areas, such as the Russia-Ukraine war, and global health crises, such as the COVID-19 pandemic, can also impact the global economy and decrease worldwide demand for oil and refined products, which affects the prices of crude oil. Increased volatility in the global oil markets, including the prices our revenues; if those revenues were significantlycustomers and suppliers pay for crude oil and other raw materials, has, and may continue to, materially adversely affect our business, financial condition, results of operations and/or cash flows as well as our ability to pay distributions to our common unitholders.

Adverse developments in the global economy or in regional economies could also negatively impact our customers and suppliers, and therefore have a negative impact on our business or financial condition. In the event of adverse developments or stagnation in the economy or financial markets, our customers and suppliers may experience deterioration of their businesses, reduced theredemand for their products, cash flow shortages and difficulty obtaining financing. As a result, existing or potential customers might delay or cancel plans to use our services and may not be able to fulfill their obligations to us in a timely fashion. Further, suppliers may experience similar conditions, which could beimpact their ability to fulfill their obligations to us. Moreover, a financial market crisis may have a material adverse effectimpact on financial institutions and limit access to capital and credit. This could, among other things, make it more difficult for us to obtain ( or increase our resultscost of operations.

For the year ended December 31, 2017, Delek accountedobtaining) capital and financing for 8% of the combined revenues of our petroleum product and crude pipelines and of our terminals and truck loading racks, including revenues we received from Delek under a capacity lease agreement. If Delek satisfies only its minimum obligations under the long-term pipeline and terminal, tankage and throughput agreements that it has withoperations. Our access to additional capital may not be available on terms acceptable to us or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at Delek’s refineries, our revenues and cash flow would decline.all.

A decline in production at Delek's Big Spring refinery could reduce materially the volume of refined products we transport and terminal for Delek and, as a result, our revenues could be materially adversely affected. The Big Spring refinery could partially or completely shut down its operations, temporarily or permanently, due to factors affecting its ability to produce refined products or for planned maintenance or capital projects. Such factors would include the factors discussed above under the discussion of risk with respect to the Navajo refinery.



The effect on us of any shutdown depends on the length of the shutdown and the extent of the refinery operations affected. We have no control over the factors that may lead to a shutdown or the measures Delek may take in response to a shutdown. Delek makes all decisions and is responsible for all costs at the Big Spring refinery concerning levels of production, regulatory compliance, refinery turnarounds, labor relations, environmental remediation, emission control and capital expenditures.

In addition, under our throughput agreement with Delek, if we are unable to transport or terminal refined products that Delek is prepared to ship, then Delek has the right to reduce its minimum volume commitment to us during the period of interruption. If a force majeure event occurs, we or Delek could terminate the Delek pipelines and terminals agreement after the expiration of certain time periods. The occurrence of any of these events could reduce our revenues and cash flows.

Due to our lack of asset and geographic diversification, an adverse developmentsdevelopment in our businesses could materially and adversely affect our financial condition, results of operations or cash flows.


We rely exclusively on the revenues generated fromA significant concentration of our business.pipeline assets serve HF Sinclair's Navajo refinery. Due to our lack oflimited asset and geographic diversification, especially our large concentration of pipeline assets serving the Navajo refinery, an adverse development in our business (including adverse developments due toas a result of catastrophic events or weather, including as a result of climate change, terrorist or cyberattacks, vandalism, public health crisis, decreased supply of crude oil and feedstocks and/or decreased demand for refined petroleum products), could have a significantly greater impact on our financial condition, and results of operations or cash flows than if we maintained more diverse assets in more diverse locations.


Our leverage may limitAny reduction in the capacity of, or the allocations to, our ability to borrow additional funds, comply withshippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.

HF Sinclair and the termsother users of our indebtednesspipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, catastrophic events, terror or capitalize on business opportunities.

As of December 31, 2017, the principal amount of our total outstanding debt was $1,512 million. Our results of operations, cash flows and financial positioncyberattacks, vandalism or other causes could be adversely affected by significant increasesresult in interest rates above current levels. Various limitationsreduced volumes transported in our Credit Agreementpipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals.

A material decrease in the supply, or a material increase in the price, of crude oil or other materials available to HF Sinclair's refineries and our pipelines and terminals, and a corresponding decrease in demand for refined products in the indenture formarkets served by our 6.0% senior notes due 2024 (the "6% Senior Notes") maypipelines and terminals, could reduce our ability to incur additional debt, to engagerevenues materially.

The volume of refined products we transport in some transactions and to capitalizeour refined product pipelines depends on business opportunities. Any subsequent refinancingthe level of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance,production of refined products from HF Sinclair's refineries, which, in turn, is subjectdepends on the availability of attractively-priced crude oil produced in the areas accessible to then-current economic conditionsthose refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries, as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production declines, governmental regulations, including travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, catastrophic events or otherwise, could result in a decline in the volume of crude oil our shippers refine, absent the availability of transported crude oil to financial, businessoffset such declines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However,therefore a significant downturncorresponding reduction in our businesscash flow. In addition, the future growth of our
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shippers' operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in their currently connected supplies.

Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over producers or their production decisions, which are affected by, among other development adversely affectingthings, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation, global market conditions, actions by foreign nations and the availability and cost of capital, or over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. Similarly, a material increase in the price of crude oil supplied to refineries without an increase in the market value of the products produced by the refineries, either temporary or permanent, which causes a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, and our cash flow could be adversely affected.

In addition, periods of disruption in the global supply chain, including as a result of COVID-19, have caused shortages in the equipment and parts necessary to operate our facilities and to complete our capital projects. Certain suppliers have experienced, and may continue to experience, delays related to a variety of factors, including logistical delays and component shortages from vendors. We continue to monitor the situation and work closely with our suppliers to minimize disruption to our operations as a result of supply chain interruptions.

Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, global pandemic, technological advances in fuel economy and energy-generation devices, exploration and production activities, actions by foreign nations, and any potential litigation related to climate change effects and resulting negative public perception, any of which could reduce the demand for the petroleum products in the areas we serve. The volatility in global oil markets, while uncertain, has, and may continue to, materially impairadversely affect our business, financial condition, results of operations and/or cash flows, as well as our ability to servicepay distributions to our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, wecommon unitholders.

Competition from other pipelines that may be forced to refinance all or a portion of our debt or sell assets. We cannot guarantee that we would be able to refinancesupply our existing indebtednessshippers' customers with refined products at maturity or otherwise or sell assets on terms that are commercially reasonable.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain beneficial transactions. The agreements governing our debt generally requirea lower price could cause us to complyreduce our rates or could reduce our revenues.

We and our shippers could face increased competition if other pipelines are able to supply our shippers' end-user markets competitively with various affirmativerefined products. For example, increased supplies of refined product delivered by Kinder Morgan's El Paso to Phoenix pipeline could result in additional downward pressure on wholesale-refined product prices and negative covenants includingrefined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the maintenance of certain financial ratiosEl Paso and restrictionsArizona markets on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Our leverage may affect adversely our ability to fund future working capital, capital expendituresthis and other general partnership requirements,pipelines and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from HF Sinclair. This could reduce our opportunity to earn revenues from HF Sinclair in excess of its minimum volume commitment obligations.

An additional factor that could affect some of HF Sinclair's markets is excess pipeline capacity from the West Coast into our shippers' Arizona markets. Additional increases in shipments of refined products from the West Coast into our shippers' Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by HF Sinclair to these markets.

Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions such as natural disasters, adverse weather, earthquakes, accidents, fires, explosions, hazardous materials releases or spills (such as the release of crude oil on the Osage pipeline in July 2022), terror or cyberattacks, vandalism, power failures, mechanical failures and other events beyond our control, and we have experienced certain of these events in the past. These events could result in an injury or loss of life; and have in the past and could in the future acquisitions, constructionresult in property damage or development activities,destruction or to otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtednesscurtailment or to comply with any restrictive terms of our indebtedness. Our leverage also may make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changesinterruption in our business and the industryoperations. In addition, third-party damage, mechanical malfunctions, undetected leaks in which we operate andpipelines, faulty measurement or other errors may place us at a competitive disadvantage as compared to our competitors that have less debt.result in significant costs or lost revenues.


We may not be able to maintain or obtain funding on acceptable terms orinsurance of the type and amount we desire at commercially reasonable rates and exclusions from coverage may limit our ability to recover the amount of the full loss in all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions.situations. As a result the cost of raising money in the debtmarket conditions, premiums and equity capital marketsdeductibles for certain of our insurance policies and insurance policies for our joint ventures are increasing. In some instances, certain insurance has become unavailable or has become available only for reduced amounts of coverage or at a significantly increased substantially at times while the availability of fundscost.

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There can be no assurance that insurance will cover all or any damages and losses resulting from these markets diminished significantly. In particular, astypes of hazards. We are not fully insured against all risks or incidents to our business and therefore, we self-insure certain risks. We are not insured against all environmental accidents that might occur. Our property insurance includes business interruption coverage for lost profit arising from physical damage to our facilities. If a result of concerns about the stability of financial markets generallysignificant accident or event occurs that is self-insured or not fully insured, our operations could be temporarily or permanently impaired, our liabilities and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lendersexpenses could be significant and institutional


investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations.

Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to:

meet our obligations as they come due;
execute our growth strategy;
complete future acquisitions or construction projects;
take advantage of other business opportunities; or
respond to competitive pressures.

Any of the aboveit could have a material adverse effect on our revenuesfinancial position. Because our partnership agreement requires us to distribute all available cash (less operating surplus cash reserves) to our unitholders, we do not have the same flexibility as other legal entities to accumulate cash to protect against under insured or uninsured losses.

If we are unable to complete capital projects at their expected costs or in a timely manner, if we incur increased maintenance or repair costs on assets, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and increased maintenance or repair expenditures on our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of numerous factors, such as:

•third-party challenges to, denials, or delays in issuing requisite regulatory approvals and/or permits;
•societal and political pressures and other forms of opposition;
•compliance with or liability under environmental or pipeline safety regulations;
•unplanned increases in the cost of construction materials or labor;
•disruptions in transportation of modular components and/or construction materials;
•severe adverse weather conditions, natural disasters, terror or cyberattacks, domestic vandalism other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
•market-related increases in a project's debt or equity financing costs; and/or
•nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

The COVID-19 pandemic or any other widespread outbreak of an illness or pandemic or other public health crisis, and actions taken in response thereto, has had and may continue to have a material adverse effect on our operations, business, financial condition, results of operations or cash flows.

COVID-19’s spread across the globe and government regulations in response thereto have negatively affected worldwide economic and commercial activity, impacted global demand for oil, gas and refined products, and created significant volatility and disruption of financial and commodity markets. The spread of COVID-19 has caused us to modify our business practices from time to time as needed (including limiting employee and contractor presence at our work locations, restricting travel unless approved by senior leadership, quarantining employees when necessary and reducing utilization at our refineries) and could significantly disrupt our operations and ability to perform critical functions in the future. The effects of COVID-19 or any other pandemic are difficult to predict, and the duration of any potential business disruption or the extent to which it may negatively affect our operating results or our liquidity is unknown. The extent to which the COVID-19 pandemic will continue to impact our business and operating results remains undetermined and depends on future developments related to the duration and severity of the spread of the virus, emerging variants, vaccine and booster effectiveness, and government measures, designed to slow and contain the spread of COVID-19, among others, and, all of which are beyond our control. These effects of the COVID-19 pandemic, while uncertain, have, and may continue to, materially adversely affect our business, financial condition, results of operations and/or cash flows, as well as our ability to pay distributions to our common unitholders.

We may be unsuccessful in integrating the operations of the assets we have acquired or may acquire with our operations, including the Sinclair business acquired in the HEP Transaction, and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses, such as the HEP Transaction with Sinclair.Acquisitions such as the HEP Transaction require, and may continue to require, management to devote significant attention and resources to integrating the acquired business with our business.We may encounter difficulties integrating personnel from the acquired business while maintaining focus on providing consistent, high-quality products and services.The disruption of, or the loss of momentum in, each company's ongoing business or inconsistencies in standards, controls, procedures and policies may result from the integration process.Further, we may lose key employees or encounter difficulties integrating relationships with customers, vendors, and business partners.

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
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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.

Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations.operations may change significantly as a result of completed or future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them, and new geographic areas and the diversion of management's attention from other business concerns. Performance at HEP or the acquired business may suffer as a result of any such diversion of management’s attention.Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Also, following an acquisition, we may discover previously unknown and unforeseen liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.


We maymay not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities, if our assumptions concerning population growth are inaccurate, or if an agreement cannot be reached with HFCHF Sinclair for the acquisition of assets on which we have a right of first offer.


Our strategy contemplates growth through the development and acquisition of crude, intermediate and refined products transportation and storage assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses, either from HFCHF Sinclair or third parties, to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand-alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in our chosen businesses and increase our market position.


We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, or if the development or acquisition opportunities are on terms that do not allow us to obtain appropriate financing, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, credit ratings, covenants, underwriting or loan origination fees and similar charges we pay to lenders.


In addition, we experience competition for the types of assets and businesses we have historically purchased or acquired. High competition, particularly for a limited pool of assets, may result in higher, less attractive asset prices, and therefore, we may lose to more competitive bidders. Such occurrences limit our ability to execute our growth strategy, which may materially adversely affect our ability to maintain or pay higher distributions in the future.


Our growth strategy also depends upon:


•the accuracy of our assumptions about growth in the markets that we currently serve or have plans to serve in the Southwestern, Northwest and Mid-Continent regions of the United States;
HFC's•HF Sinclair's willingness and ability to capture a share of additional demand in its existing markets; and
HFC's•HF Sinclair's willingness and ability to identify and penetrate new markets in the Southwestern, Northwest and Mid-Continent regions of the United States.


If our assumptions about increased market demand prove incorrect, HFCHF Sinclair may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy.


Our Omnibus Agreement with HFCHF Sinclair provides us with a right of first offer on certain of HFC’sHF Sinclair’s existing or acquired logistics assets. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to the assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be terminated upon a change of control of HFC.HF Sinclair.

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We are exposed todo not own all of the credit risks and certain other risks, ofland on which our key customers, vendors,pipeline systems and other counterparties.

Weassets are subjectlocated, which could result in disruptions to risksour operations. Additionally, a change in the regulations related to a state’s use of loss resulting from nonpayment or nonperformance by our customers, vendors or other counterparties. We derive a significant portion of our revenues from contracts with key customers, including HFC and Delek under their respective pipelines and terminals, tankage, tolling and throughput agreements. To the extent that our customers may be unable to meet the specifications of their customers, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.

Mergers among our existing customerseminent domain could provide strong economic incentives for the combined entities to use systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduceinhibit our ability to meet our financial obligations and make distributions to unitholders.

If anysecure rights-of-way for future pipeline construction projects. Finally, certain of our key customers defaultassets are located on their obligationsor adjacent to us,Native American tribal lands.

We do not own all of the land on which our financial resultspipeline systems and other assets are located, and we are, therefore, subject to the risk of increased costs or more burdensome terms to maintain necessary land use. We obtain the right to construct and operate pipelines and other assets on land owned by third parties and government agencies for specified periods. If we were to lose these rights through an inability to renew leases, right-of-way contracts or similar agreements, we may be required to relocate our pipelines or other assets and our business could be adversely affected. Furthermore, someAdditionally, it may become more expensive for us to obtain new rights-of-way or leases or to renew existing rights-of-way or leases. If the cost of obtaining or renewing such agreements increases, it may adversely affect our operations and the cash flows available for distribution to unitholders.

The adoption or amendment of laws and regulations that limit or eliminate a state’s ability to exercise eminent domain over private property in a state in which we operate could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects.

Certain of our customerspipelines are located on or adjacent to Native American tribal lands. Various federal agencies, along with each Native American tribe, promulgate and enforce regulations, including environmental standards, regarding operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations (including various taxes, fees, and other requirements and conditions) and to grant approvals independent from federal, state and local statutes and regulations. Following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Native American landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operations. In addition, following the Supreme Court's ruling in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished, and therefore retains jurisdiction over criminal matters, and a subsequent ruling in July 2022 in Oklahoma v. Castro-Huerta narrowing McGirt’s holding to find concurrent tribal and state jurisdiction with respect to crimes committed by non-Native Americans against Native Americans on tribal lands, substantial uncertainty exists with respect to matters over which tribes may have exclusive or concurrent jurisdiction. Although the ruling in McGirt indicates that it is limited to criminal law, the ruling has significant potential implications for civil law. At this time, we cannot predict how these jurisdictional issues may ultimately be highly leveraged andresolved. These factors may increase our cost of doing business on Native American tribal lands.

In addition, our industry is subject to their own operatingpotentially disruptive activities by those concerned with the possible environmental impacts of pipeline routes. Activists, non-governmental organizations and regulatory risks. In addition, nonperformanceothers may seek to restrict the transportation of crude oil and refined products by vendors who have committedexerting social or political pressure to provide us with productsinfluence when, and whether, such rights-of-way or servicespermits are granted. This interference could result in higher costs orimpact future pipeline development, which could interfere with our ability to successfully conduct our business.
Any substantial increase in the nonpayment and/or nonperformance by our customersblock expansion or vendorsdevelopment projects and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties, including HFC, have agreed to indemnify us, subject to certain limitations, for:

certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition;
certain matters arising from the pre-closing ownership and operation of assets; and
ongoing remediation related to the assets.

Our business, results of operation, cash flows and our ability to make cash distributions to our unitholders could be adversely affectedunitholders.

Our business may suffer due to a change in the composition of our Board of Directors, the departure of any of our key senior executives or other key employees who provide services to us, or if certain of our executive officers, who also allocate time to our general partner and its affiliates, do not have enough time to dedicate to our business. Furthermore, a shortage of skilled labor or disruptions in the labor force that provides services to us may make it difficult for us to maintain labor productivity.

Our future if third parties failperformance depends to satisfy an indemnification obligation oweda significant degree upon the continued contributions of HLS's Board of Directors, key senior executives and key senior employees who provide services to us.

Competition from other pipelines that may be able to supply Also, our shippers' customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.

We and our shippers could face increased competition if other pipelines are able to supply our shippers' end-user markets competitively with refined products. For example, increased supplies of refined product delivered by Kinder Morgan's El Paso to Phoenix pipeline could result in additional downward pressure on wholesale-refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from HFC and/or Delek. This could reduce our opportunity to earn revenues from HFC and Delek in excess of their minimum volume commitment obligations.

An additional factor that could affect some of HFC's and Delek's markets is excess pipeline capacity from the West Coast into our shippers' Arizona markets. Additional increases in shipments of refined products from the West Coast into our shippers' Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by HFC and Delek to these markets.

A material decrease in the supply, or a material increase in the price, of crude oil available to HFC's and Delek's refineries, and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could reduce our revenues materially.

The volume of refined products we transport in our refined product pipelinesbusiness depends on the levelcontinuing ability to recruit, train and retain highly qualified employees in all areas of productionour operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of refined products from HFC'sthese executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and Delek's refineries, which,are not adequately replaced, our business operations could be materially adversely affected. We do not currently maintain “key person” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in turn, depends on the availabilitymultiple tasks. A shortage of attractively-priced crude oil producedtrained workers due to retirements or otherwise or an increase in the areas accessible to those refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries,labor costs as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production declinesinflation or otherwise could resulthave an adverse impact on productivity and costs, which could adversely affect our operations.

Our general partner shares officers and administrative personnel with HF Sinclair to operate both our business and HF Sinclair's business. These officers face conflicts regarding the allocation of their and other employees' time, which may affect adversely our results of operations, cash flows and financial condition.

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A portion of HF Sinclair's employees that are seconded to us from time to time are represented by labor unions under collective bargaining agreements with various expiration dates. HF Sinclair may not be able to renegotiate the collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, existing labor agreements may not prevent a future strike or work stoppage, and any work stoppage could negatively affect our results of operations and financial condition.

Terrorist attacks, and the threat of terrorist attacks or vandalism, have resulted in increased costs to our business. Global hostilities may adversely impact our results of operations.

The long-term impact of (and threat of future) terrorist attacks and vandalism, on the energy transportation industry in general, and on us in particular, is unknown. Any attack on our facilities, those of our customers and, in some cases, those of other pipelines could have a declinematerial adverse effect on our business. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business.

The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets or our operations could be disrupted. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

Uncertainty surrounding global hostilities or other sustained military campaigns, and the volumepossibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror, may affect our operations in unpredictable ways, including disruptions of crude oil our shippers refine, absent the availability of transported crude oil to offset such


declines. Such an event would result in an overall decline in volumes ofsupplies and markets for refined products transported throughor instability in the financial markets that could restrict our pipelines and therefore a corresponding reduction in our cash flow. ability to raise capital.

In addition, changes in the future growthinsurance markets attributable to terrorist attacks, vandalism, or cyberattacks or extortion could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism, cyberattacks, vandalism or war could also affect our ability to raise capital, including our ability to repay or refinance debt.

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications. In addition, we could be required to make substantial expenditures in the event of any changes in product quality specifications.

A significant portion of our shippers' operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate thanoperating responsibility on refined product pipelines is to manage the rate of natural decline in their currently connected supplies.

Fluctuations in crude oil prices can greatly affect production ratesquality and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital, or over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. Similarly, a material increase in the price of crude oil supplied to our shippers' refineries without an increase in the market valuepurity of the products producedloaded at our loading racks. If our quality control measures fail, off-specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages caused by the refineries, either temporaryoff-specification fuel or permanent, which causes a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, andcould impact our cash flow could be adversely affected.

Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations,ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.

In addition, various federal, state and local agencies have the authority to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the demand forfungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products in the areas we serve.pipeline system could reduce or eliminate our ability to blend products.

We may not be able to retain existing customers or acquire new customers.


The renewal or replacement of existing contracts with our customers at rates sufficient to maintain attractivecurrent revenues and cash flows depends on a number of factors outside our control, including competition from other pipelines and the demand for refined products in the markets that we serve.

We own certain of our systems through joint ventures, and our control of such systems is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures.

Certain of our systems are operated by joint venture entities for which we do not serve as the operator, or in which we do not have an ownership stake that permits us to control the business activities of the entity. We have limited ability to influence the business decisions of such joint venture entities.
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Because we have partial ownership in the joint ventures, we may be unable to control the amount of cash we will need for capital projects or will receive from the operation and could be required to contribute significant cash to fund our share of their projects and operations, which could adversely affect our ability to distribute cash to our unitholders.

An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our financial condition and results of operations.

An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our results of operations and financial condition. We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset or goodwill may be impaired. If a triggering event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value based on the ability to generate future cash flows. We may also conduct impairment testing based on both the guideline public company and guideline transaction methods. Our long-termlong-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, estimates of future tariff rates, forecasted throughput levels, operating costs and capital expenditures. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may need to be recorded in the future. We cannot accurately predict the amount and timing of any additional impairments of long-lived assets or goodwill in the future.

Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.

One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and terminal, tankagelegal uncertainties, most of which are beyond our control. For example, the Biden Administration temporarily suspended the grant of certain authorizations for oil and refinery processing unitgas activities on federal lands, although the order did not affect existing authorizations. Pipeline construction projects requiring federal approvals are generally subject to environmental review requirements under the National Environmental Policy Act ("NEPA"), and must also comply with other natural resource review requirements imposed pursuant to the Endangered Species Act and the National Historic Preservation Act. In April 2022, the Biden Administration revised NEPA’s implementing regulations, and now requires NEPA reviews to incorporate consideration of indirect and cumulative impacts of a proposed project, including the effects of climate change and greenhouse gas emissions. These revisions marked the end of the first phase of a two part review being undertaken by the Council on Environmental Quality (the “CEQ”), and thus additional changes to the NEPA rules may be forthcoming, though we cannot predict the substance or form of such revisions. Moreover, for over 35 years, the U.S. Army Corps of Engineers ("Corps") has authorized construction, maintenance, and repair of pipelines under a streamlined nationwide permit program under the federal Clean Water Act (“CWA”) known as Nationwide Permit 12 (“NWP 12”) program. From time to time, environmental groups have challenged the use of NWP 12 for oil and gas pipeline projects. In April 2020, the U.S. District Court for the District of Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act, vacated NWP 12, and enjoined the issuance of new authorizations for oil and gas pipeline projects under NWP 12, though the district court’s order was subsequently limited on appeal. In January 2021, the Corps published a reissuance of NWP 12, but this permit is similarly being challenged in federal court on the same grounds that were litigated in the April 2020 case. More recently, in May 2022 the Corps announced it was beginning a formal review of NWP 12. The outcome of litigation involving the Biden Administration’s Social Cost of Carbon (“SCC”) metric may also impact future regulatory decision-making with respect to our construction and development. In May 2022, the Fifth Circuit stayed a lower court’s order blocking the Biden Administration’s use of an interim SCC value while the government’s appeal remains in progress. While the full extent and impact of these recent developments is unclear at this time, we could face significant delays and financial costs if we must obtain individual permit coverage from the Corps for our projects or satisfy more stringent environmental conditions or reviews. These projects may not be completed on schedule (or at all) or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project.

Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput agreements with HFCto achieve our expected investment return, which could adversely affect our earnings, results of operations and Delek expire beginning in 2019 through 2036.financial condition.


RISKS RELATED TO GOVERNMENT REGULATION

Our operations are subject to evolving federal, state and local laws, regulations and permit/authorization requirements regarding our business, capital projects and environmental protection, health, operational safety and product quality. Potential liabilities arising from these laws, regulations and requirements could affect our operations and adversely affecthave a material adverse effect on our performance.business.

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Our pipelines and terminal, tankage and loading rack operations are subject to increasingly strict environmentalstringent federal, state, and safetylocal laws, regulations and regulations.oversight regarding, among other things, the generation, storage, handling, use, transportation and distribution of petroleum and hazardous materials by pipeline, truck, rail, ship and barge, the emission and discharge of materials into the environment, waste management, the characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of human health and the environment and natural resources, including climate change.


Environmental laws and regulations have raised operating costs for the oil and refined products industry, and compliance with such laws and regulations may cause us, the HF Sinclair refineries, and the HFC and Delekother refineries that we support to incur potentially material capital expenditures associated with the construction, maintenance, and upgrading of equipment and facilities. Future environmental, health and safety requirements (or changed interpretations of existing requirements), may impose new and/or more stringent requirements on our assets and operations and require us to incur potentially material expenditures to ensure our continued compliance.comply. Failure to comply with any applicable laws, regulations, and requirements of regulatory authorities could subject us to substantial penalties and fines.


Our operations require numerous permitsauthorizations and authorizationspermits under various laws and regulations, including environmental and worker health and safety laws and regulations. In May 2015, the EPA published a final rule that has the potential to greatly expand the definition of "waters of the United States" under the federal Clean Water Act ("CWA") and the jurisdiction of the Corps. The rule is currently subject to a number of legal challenges in federal court. The EPA and the Corps have proposed to repeal the May 2015 rule and have separately announced their intention to issue a revised rule defining the scope of the CWA's jurisdiction. The agencies have also issued a stay delaying implementation of the rule for two years. To the extent any final rule on the scope of the CWA expands jurisdictional waters, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. These and other authorizations and permits are subject to revocation, renewal, modification, or third partythird-party challenge, and can require operational changes that may involve significant costs to limit impacts or potential impacts on the environment and/or worker health and safety. For example, on January 23, 2020, the EPA, in conjunction with the Corps, issued a final rule regarding the definition of "waters of the United States," which became effective June 22, 2020 and narrowed the regulatory reach of the CWA regulations relative to a prior 2015 rulemaking. However, that rule was vacated by one court in 2021, and the Biden Administration subsequently announced a proposed rule that would generally reinstate with modifications the pre-2015 definition of “waters of the United States.” The proposed rule was finalized on January 18, 2023, and will become effective March 20, 2023. This new rule expands CWA jurisdiction relative to the June 2020 rule and will likely be subject to further litigation. This increase in scope could result in increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations and injunctions prohibiting our operations. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment that could have a material adverse effect on our business, financial condition, results of operations and cash flows.




We may also be required to address conditions discovered in the future that require environmental response actions or remediation. The transportation and storage of refined products produces a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. Further, we own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. Environmental laws can impose strict, joint and several liability for releases of oil and hazardous substances into the environment, and we could find ourselvesbe held liable for past releases caused by third parties. If we were to incur a significant liability pursuant to environmental laws or regulations, it could have a material adverse effect on us.


Currently,Our operations are also subject to various legislativelaws and regulatory measuresregulations relating to address greenhouse gas emissions (including carbon dioxide, methaneoccupational health and other gases) are in various phasessafety, including chemical accident prevention. We maintain safety, training and maintenance programs as part of discussion or implementation. These include requirementsour ongoing efforts to comply with applicable laws and regulations but cannot guarantee that HFC'sthese efforts will always be successful. Compliance with applicable health and Delek's refineries report emissions of greenhouse gasessafety laws and regulations has required and continues to the EPA,require substantial expenditures. Failure to appropriately manage occupational health and proposed federal, state, and regional initiatives that require (or could require) us, HFC and Delek to reduce greenhouse gas emissions from our facilities. Requiring reductions in greenhouse gas emissions could cause us to incur substantial costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of emission credits or allowances or the payment of carbon taxes. These requirements may affect HFC's and Delek's refinery operations and have an indirect adverse effect onsafety risks associated with our business financial conditioncould also adversely impact our employees, communities, reputation and results of our operations.


Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels could also decrease demand for refined products, which could have an indirect, but material, adverse effect on our business, financial condition and results of operations. For example, in 2010 and again in 2016, the EPA promulgated a rule establishing greenhouse gas emission standards for new-model passenger cars, light-duty trucks, and medium-duty passenger vehicles. Also in 2010, the EPA promulgated a rule establishing greenhouse gas emission thresholds for the permitting of certain stationary sources, which could require greenhouse emission controls for those sources. In addition, the EPA finalized new regulations in 2016 that limit methane emissions from certain new and modified oil and gas facilities. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. These requirements could, to the extent fully implemented, result in increased compliance costs and could also have an indirect adverse effect on our business due to reduced demand for crude oil and refined products, and a direct adverse effect on our business from increased regulation of our facilities.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

We are regulated under federal pipeline safety statutes by DOT through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”). PHMSA sets and enforces pipeline safety regulations. Failure to comply with PHMSA or comparable state pipeline safety regulations could result in a number of consequences which may have a materially adverse effect on our operations. PHMSA’s enforcement authority includes the ability to assess civil penalties for violations of pipeline safety regulations, issue orders directing compliance, and issue orders directing corrective action to abate hazardous conditions. Among other things, pipeline safety laws and regulations require pipeline operators to develop and implement integrity management programs, including more frequent inspections and other measures for certain pipelines that,located in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including certain population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to perform a variety of heightened assessment, analysis, prevention and repair activities.activities on the segments of pipe located within high
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consequence areas. Routine assessments under the integrity management program may result in findings that require repairs or other actions.


Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly pipeline integrity management or safety standards could possibly have a substantial effect on us and similarly situated midstream operators. In December 2020, Congress passed the PIPES Act, some elements of which could affect our operations. Further, PHMSA adopted new regulations related to Valve Installation and Minimum Rupture Detection Standards, which became effective on October 5, 2022. These regulations expand PHMSA's regulation of the safety of hazardous liquid pipelines by establishing certain new procedural and notification requirements for managing rupture events, and requiring the installation of rupture-mitigation valves on new or certain replaced pipelines. This final rule may result in additional capital and operations and maintenance costs in the coming years. Additionally, where PHMSA has not pursued any legal requirements, state agencies, to the extent authorized, could enact regulatory standards for certain pipelines.


FederalRate regulation, changes to rate-making rules, or a successful challenge to the rates we charge on our pipeline systems may reduce our revenues and the amount of cash we generate.

For a general overview of federal and state legislativeregulations applicable to our pipeline assets, see “Overview – Governmental Regulation” included within Part I, Items 1 and regulatory initiatives relating2 “Business and Properties” of this annual report. The federal and state regulations that apply to our pipeline safetyassets can affect certain aspects of our business and the market for our products and can have a material adverse effect on our financial position, results of operations and cash flows.

The FERC, pursuant to the ICA and the rules and orders promulgated thereunder, regulates the tariff rates and terms and conditions of service on our interstate liquids pipelines. To be lawful under the ICA, tariff rates and terms and conditions of service must be on file at FERC, just and reasonable, and not unduly discriminatory. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected (including interest) pursuant to rates that requireare ultimately found to be unlawful and prescribe new rates prospectively. The FERC and interested parties can also challenge tariff rates and provisions that have become final and effective. The FERC can also order new rates to take effect prospectively and order reparations (plus interest) for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of newrates reflecting increased costs. We believe the transportation rates currently charged by our interstate liquids pipelines are in accordance with the ICA and applicable FERC regulations. However, due to the complexity of rate making, the lawfulness of any rate is never assured. Adverse decisions by the FERC related to our rates could adversely affect our revenue, financial position, results of operations, and cash flows. In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to the affected assets.

The intrastate liquids and natural gas pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. These state commissions have generally not been aggressive in regulating common carrier pipelines and generally have not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints. However, a state regulatory commission could investigate our rates if such a challenge were filed and any adverse decisions could adversely affect our revenue, financial position, results of operations, and cash flows.

There are various risks associated with greenhouse gases, climate change legislation or regulations, and increasing societal expectations that companies address climate change that could result in increased operating costs, reduced demand for our services and reduced access to capital markets.

Climate change continues to attract considerable attention in the United States. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases. These efforts have included consideration of cap-and-trade programs, carbon taxes, climate-related disclosure obligations, and regulations that directly limit greenhouse gas emissions from certain sources. While it presently appears unlikely that comprehensive climate change legislation will be passed by Congress in the near future, energy legislation and other regulatory initiatives are expected to be proposed that may be relevant to greenhouse gas emissions issues. Moreover, in 2021, President Biden issued several executive orders that committed to substantial action on climate change and released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency, decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels, eliminating subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. As
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a result, our operations, and those of our customers, are subject to a series of regulatory, political, litigation, and financial risks associated with the transport of fossil fuels and emission of greenhouse gases.

The EPA has adopted rules that, among other things, establish construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources, require the monitoring and annual reporting of greenhouse gas emissions from certain petroleum and natural gas sources in the United States or require control or reduction of emissions of greenhouse gases, including methane, from such sources. In 2021, the EPA announced its intent to reconsider and revise rules related to the oil and gas sector (primarily oil production and natural gas production, distribution, and storage) to further reduce greenhouse gas emissions, and on December 6, 2022, the EPA proposed a supplement that would revise and expand the 2021 proposal. Separately, the Bureau of Land Management (“BLM”) has also proposed rules to limit venting, flaring, and methane leaks for oil and gas operations on federal lands, which could in turn adversely impact production of oil and gas on federal lands and reduce demand for the services we provide in those areas. More recently, in January 2023, the CEQ released updated guidance for agency consideration of greenhouse gas emissions and climate change impacts in environmental reviews, which includes, among other recommendations, best practices for analyzing and communicating climate change effects. In addition, the EPA, together with the DOT, implemented greenhouse gas emission and corporate average fuel economy standards for vehicles manufactured in the United States, which standards were revised in December 2021 to impose more stringent safety controlsrequirements for emissions reductions. President Biden also reinstated the Interagency Working Group on the Social Cost of Greenhouse Gases in 2021 and directed the group to publish interim estimates of the social cost of carbon dioxide, nitrous oxide, and methane, with a view to using such estimates in federal rulemakings greenhouse gases, which it did. In November 2022, the EPA published a draft report assigning new and higher social cost values to greenhouse gas emissions for use in its rulemaking initiatives. These and other federal efforts to reduce greenhouse gas emissions from the transportation sector could increase our operating costs or reduce demand for our customers’ products.

In March 2022, the SEC issued proposed rules that, if adopted, would require public companies to include certain climate-related disclosures in their registration statements and periodic reports, including information about climate-related risks, climate-related financial statement metrics, and greenhouse gas emissions. In November 2022, the Biden Administration issued a proposed rule that would require government contractors to publicly disclose their greenhouse gas emissions and set emissions reduction targets, which could affect us if we enter into contractual and business arrangements with government contractors.

Internationally, the United Nations-sponsored Paris Agreement requires member nations to submit non-binding, individually determined emissions reduction goals every five years after 2020. In 2021, the United States rejoined the Paris Agreement and issued its corresponding “nationally determined contribution” (“NDC”) to reduce economy-wide net greenhouse gas emissions 50-52% below 2005 levels by 2030. While the NDC does not identify specific actions necessary to achieve these reductions, it lists several sectors as pathways for reductions, including the power, transportation, building, industrial, and agricultural sectors. The administration has acknowledged that a combination of regulatory actions and legislation will be necessary to achieve the U.S. NDC. In regards to legislation, in November 2021 the United States enacted a nearly $1 trillion bipartisan infrastructure law, which provided significant funding for electric vehicles and clean energy technologies, and in August 2022 the United States enacted the Inflation Reduction Act of 2022, which allocated $369 billion to climate change and environmental initiatives, including transportation electrification, fees on and greater regulation of methane emissions, and support for green energy manufacturing programs. Certain of these initiatives are subject to ongoing litigation, and the impacts of these international initiatives and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates and combustion engine phaseouts. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the crude oil and refined products that we deliver.

Increasing societal expectations that companies address climate change, including international, federal, state and local rules and regulations relating to climate change driven by such societal expectations, and use of substitutes for energy commodities may result in increased costs, reduced demand for our customers’ products and our services, reduced profits, increased investigations and litigation, diversion of financial resources from other initiatives and negative impacts on our unit price and access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed on us without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. In addition, certain capital markets participants, including certain institutional investors and indices, have been divesting and promoting divestment of or screening out of fossil fuel equities, which could have a negative impact on our unit price and our access to and costs of capital. There is also the possibility that financial institutions may be pressured or required to adopt policies that limit funding for fossil fuel energy companies. For example, in January 2023 the Federal Reserve published instructions for its pilot climate scenario analysis exercise, which the six largest American banks are required to complete by July 31, 2023. Any material reduction in the capital available to the fossil fuel industry could make it more stringent enforcementdifficult
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to secure funding for exploration, development, production, transportation, and processing activities, which could adversely impact our business and operations.

Finally, increasing concentrations of applicablegreenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets or those of our customers or disrupt our supply chains and thus could have an adverse effect on our operations or demand for our services. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production.

Increasing attention to environmental, social and governance (“ESG”) matters may adversely impact our business, financial results, stock price or price of debt securities.

In recent years the investment community, including investment advisors, sovereign wealth funds, pension funds, universities, financial institutions, including institutional banks, lenders, and insurance companies, and other groups have become more attentive to ESG and sustainability related practices and have been lobbied intensively, and often publicly, by environmental activists concerned about climate change to limit or curtail activities with fossil fuel energy companies. There has also been an increase in third-party providers of company ESG ratings, and more ESG-focused voting policies among proxy advisory firms, portfolio managers, and institutional investors. As a result, some investors, funds, financial institutions and other capital markets participants may screen companies such as ours for ESG performance before investing in our common stock or debt securities, or lending to us or have imposed restrictions upon or otherwise limited lending to, investing in, or providing insurance coverage for, companies that operate in industries with higher perceived environmental exposure, such as the energy industry. If we are unable to meet the ESG standards or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for ESG-focused activism, we may face increased costs of or limitations on access to capital or insurance necessary to sustain or grow our business, the price of our common stock or debt securities may be adversely impacted, demand for our services and refined petroleum products may be adversely impacted, and our reputation may be adversely affected, all of which could adversely impact our future financial results.

Members of the investment community are also increasing their focus on ESG practices and disclosures, including those related to climate change, GHG emissions targets, business resilience under the assumptions of demand-constrained scenarios, and net-zero ambitions in the energy industry in particular, as well as diversity, equality, and inclusion initiatives, political activities, and governance standards among companies more generally. As a result, we may face increasing pressure or negative publicity regarding our ESG practices and disclosures and demands for ESG-focused engagement from investors, stakeholders, and other interested parties. This could result in higher costs, disruption and diversion of management attention, an increased strain on our resources, and the implementation of certain ESG practices or disclosures that may present a heightened level of legal requirementsand regulatory risk, or that threaten our credibility with other investors and stakeholders.

RISKS RELATED TO CYBERSECURITY, DATA SECURITY AND PRIVACY, INFORMATION TECHNOLOGY AND INTELLECTUAL PROPERTY

Our business is subject to information technology and cybersecurity risks to operational systems, security systems, infrastructure, and customer data processed by us, third-party vendors or suppliers, and any material failure, weakness, interruption, cyber event, including an incident or breach of security, could prevent us or third parties we rely on from effectively operating our business, harm our reputation or materially adversely affect our business, results of operations or financial condition.

Our business is dependent upon increasingly complex information technology systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure collection, processing, maintenance, storage and transmission of information is critical to our operations. We are at risk for interruptions, outages and breaches of operational systems, including business, financial, accounting, data or processing, owned by us or our third-party vendors or suppliers; or third-party data that we process or our third-party partners process on our behalf. Such cyber incidents could materially disrupt or shut down operational systems; result in loss of, access to, or copying or transfer of intellectual property, trade secrets or other proprietary or competitively sensitive information; compromise certain information of customers, employees, suppliers, drivers or others; and jeopardize the security of our facilities. We monitor our information technology systems on a 24/7 basis in an effort to detect cyberattacks, security breaches or unauthorized access. Preventative and detective measures we utilize include independent cybersecurity audits and penetration tests. We implemented these efforts along with other risk mitigation procedures designed to detect and address unauthorized and damaging activity on our network, stay abreast of the increasing cybersecurity threat landscape and improve our cybersecurity posture, but such efforts will require updates and improvements and there is no guarantee that such measures will be adequate to detect, prevent or mitigate cyber incidents. Any implementation, maintenance, segregation and improvement of our systems may require significant management time, support and cost and may not be effective or adequate.

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A cyber incident could be caused by disasters, insiders (through inadvertence or with malicious intent) or malicious third parties (including nation-states or nation-state supported actors) using sophisticated, targeted methods to circumvent firewalls, encryption and other security defenses, including hacking, fraud, trickery or other forms of deception that are generally beyond our control despite our implementation of protective measures. While there have been immaterial incidents of unauthorized access to our information technology systems, we have not experienced any material impact on our business or operations from these attacks. In addition, information technology system failures, communications network disruptions (whether intentional by a third party or due to natural disaster), and security breaches could still impact equipment and software used to control plants and pipelines, resulting in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products and other damage to our facilities for which we could be held liable. These information technology system failures, communications network disruptions, and security breaches could also cause us to breach our contractual arrangements with other parties, or subject us to increased capital costs, operational delaysregulatory actions or litigation.

Furthermore, we collect and costsstore sensitive data in the ordinary course of operation.
Among other things, the 2011 Amendments to the Pipeline Safety Act direct the Secretaryour business, including personally identifiable information of Transportation to study, and where appropriate based on the results and statutory factors, promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valves, leak detection, and other requirements. The 2011 Amendments also increased the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2,090,022 for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Amendmentsour employees as well as any implementationour proprietary business information and that of PHMSA regulations thereunder, reinterpretationour customers, suppliers, investors and other stakeholders. We also work with third-party partners that may in the course of existingtheir business relationship with us collect, store, process and transmit sensitive data on our behalf and in connection with our products and services offerings. Despite our security measures, ours or our third-party partners' information technology systems may become the target of cyberattacks or security breaches (including employee error, malfeasance or other intentional or unintentional breaches), which are generally beyond our control, which could result in the theft or loss of the stored information, misappropriation of assets, disruption of transactions and reporting functions, our ability to protect confidential information and our financial reporting. Our efforts to improve security and protect data may result in increased capital and operating costs to modify, upgrade or enhance our security measures to protect against such cyber-attacks and we may face difficulties in fully anticipating or implementing adequate security measures or mitigating potential harm. Moreover, as technologies evolve and cyberattacks become increasingly sophisticated, we may not be able to anticipate, detect or prevent cyberattacks or security breaches, particularly because the methodologies used by attackers change frequently or may not be recognized until after such attack is launched, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Even with insurance coverage for cyberattacks, data breaches or unauthorized access of our or a third-party partner’s information technology systems, a claim could be denied or coverage delayed. Moreover, it is increasingly difficult to buy sufficient cyber insurance coverages as the insurance market has been limiting both liability under cyber policies and the issuance of said policies, generally. A cyberattack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation, or regulations,additional costs for remediation and modification or any issuance or reinterpretationenhancement of guidance by PHMSA or any state agencies with respectour information systems to the 2011 Amendments could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any orprevent future occurrences, all of which tasks could resulthave a material and adverse effect on our business, financial condition, results of operations or cash flows.

We may be subject to information technology system failures, communications network disruptions and data breaches that are generally beyond our control.

We depend on the efficient and uninterrupted operation of third-party hardware and software systems and infrastructure, including our operating, communications and financial reporting systems. We have implemented safeguards and other preventative measures designed to protect our systems and data, however, our information technology systems and communications network, and those of our information technology and communication service providers, remain vulnerable to interruption by natural disasters, power loss, telecommunications failure, terrorist attacks, vandalism, Internet failures, computer malware, ransomware, cyberattacks, data breaches and other events unforeseen or generally beyond our control. Additionally, the implementation of social distancing measures and other limitations on our employees, service providers and other third parties in response to the COVID-19 pandemic have necessitated in certain cases to switching to remote work arrangements on less secure systems and environments. The increase in companies and individuals working remotely has increased the risk of cyberattacks and potential cybersecurity incidents, both deliberate attacks and unintentional events. Any of these events could cause system interruptions, delays, and loss of critical data, and could prevent us from operating, which could make our business and services less attractive and subject us to liability. Any of these events could damage our reputation and be expensive to remedy.



incurring increased operating costs thatIn addition, information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline and terminal operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, a system failure or data security breach could have a material adverse effect on our financial condition, results of operations or financial position. Congress made additionalcash flows.

Our business is subject to complex and evolving laws, regulations and security standards regarding data privacy, cybersecurity and data protection (“data protection obligations”). Many of these data protection obligations are subject to change and uncertain interpretation, any real or perceived failure to comply with such obligations and could result in
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claims, changes to our business practices, monetary penalties, increased cost of operations or other harm to our business.

The constantly evolving regulatory and legislative environment surrounding data privacy and protection poses increasingly complex compliance challenges, and complying with such data protection obligations could increase the Pipeline Safety Lawscosts and complexity of compliance and enforcement risks. While we do not collect significant amounts of personal information from consumers, we do have personal information from our employees, job applicants and some business partners, such as contractors and distributors. Any failure, whether real or perceived, by us to comply with applicable data privacy and protection obligations could result in 2016 thatproceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments, and negative publicity, require PHMSAus to issue additional regulationschange our business practices, increase the costs and perform studies that may or may not lead to additional requirements in the future. There are numerous, currently pending PHMSA rulemaking proceedings on a varietycomplexity of pipeline safety topics. PHMSA’s rulemakings are intended to implement the 2011compliance, and 2016 statutory changes,adversely affect our business. Our compliance with emerging data privacy/security laws, as well as any associated inquiries or investigations or any other government actions related to these laws, may increase our operating costs or subject us to legal and reputational risks, including significant awards, fines, civil or criminal penalties or judgments, proceedings or litigation by governmental agencies or customers, class action privacy litigation in certain jurisdictions and negative publicity.

In the second quarter of 2021, the Department of Homeland Security’s Transportation Security Administration (“TSA”) announced two new security directives. These directives require critical pipeline owners to comply with mandatory reporting measures, including, among other things, to appoint personnel, report confirmed and potential cybersecurity incidents to the DHS Cybersecurity and Infrastructure Security Agency (“CISA”) and provide vulnerability assessments. As legislation continues to develop and cyber incidents continue to evolve, we may be required to expend significant additional policy priorities. PHMSA has delayed implementation ofresources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to detect, assess, investigate and remediate any critical infrastructure security vulnerabilities and report any cyber incidents to the applicable regulatory authorities. Any failure to maintain compliance with these evolving government regulations but they are expected to become effective in 2018. Any such new and expanded requirements may result in additional capital costs, possible operational delaysenforcement actions which may then result in significant time, support and increased costs of operation that, in some instances, may be significant.cost and have a material adverse effect on our business and operations.



RISKS RELATED TO LIQUIDITY, FINANCIAL INSTRUMENTS AND CREDIT

Increases in interest rates could adversely affect our business.


We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our credit facility. From time to time we use interest rate derivatives to hedge interest obligations on specific debt. In addition, interest rates on future debt offerings could be higher, causing our financing costs to increase accordingly. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates aboverates.

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

As of December 31, 2022, the principal amount of our total outstanding debt was $1,556 million. On February 4, 2020, we closed a private placement of $500 million 5.0% senior notes due 2028 (the “5% Senior Notes”) and on April 8, 2022, we closed a private placement of $400 million 6.375% senior notes due 2027 (the "6.375% Senior Notes, " and together with the 5% Senior Notes, the "Senior Notes"). Various limitations in our Credit Agreement and the indenture for our Senior Notes may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current levels.indebtedness or any new indebtedness could have similar or greater restrictions.


Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to then-current economic conditions and to financial, business, competitive, regulatory and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. We cannot guarantee that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions. The agreements governing our debt generally require us to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisitions, construction or development activities, or to otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage also may make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
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We may not be subjectable to information technology system failures, network disruptionsobtain funding on acceptable terms or at all because of volatility and breachesuncertainty in data security.the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.


Information technology system failures, network disruptions (whether intentional by a third party orThe domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to natural disaster), breachesa variety of networkfactors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, including U.S. government shutdowns, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or data security,at all and reduce, or disruptionin some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or failureunable to meet their funding obligations.

Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to:

•continue our business as currently structured and/or conducted;
•meet our obligations as they come due;
•execute our growth strategy;
•complete future acquisitions or construction projects;
•take advantage of other business opportunities; or
•respond to competitive pressures.

Any of the network system used to monitor and control pipeline operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, a system failure or data security breachabove could have a material adverse effect on our financial conditionrevenues and results of operations.


If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future could be impaired materially.

Our ability to pay quarterly distributions depends primarily on cash flow (including cash flow from operations, financial reserves and credit facilities) and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods of losses and may be unable to pay cash distributions during periods of income. Our ability to generate sufficient cash from operations is largely dependent on our ability to manage our business successfully which may also be affected by economic, financial, competitive, regulatory, and other factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, quarterly distributions may also fluctuate from quarter to quarter.

We are exposed to the credit risks and certain other risks, of our or our joint ventures' key customers, vendors, and other counterparties.

We are subject to catastrophic losses, operational hazardsrisks of loss resulting from nonpayment or nonperformance by our or our joint ventures' customers, vendors or other counterparties. We and unforeseen interruptionsour joint ventures derive a significant portion of our revenues from contracts with key customers, particularly HF Sinclair, under its pipelines and terminals, tankage, tolling and throughput agreements. To the extent that our or our joint ventures' customers are unable to meet the specifications of their customers, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.

Mergers among our existing customers could provide strong economic incentives for the combined entities to use systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which wewould reduce our ability to meet our financial obligations and make distributions to unitholders.

If any of our or our joint ventures' key customers default on their obligations, our financial results could be adversely affected. Furthermore, some of our or our joint ventures' customers may not be adequately insured.

Our operations arehighly leveraged and subject to catastrophic losses, operational hazardstheir own operating and unforeseen interruptions such as natural disasters, adverse weather, tornadoes, earthquakes, accidents, fires, explosions, hazardous materials releases, cyber-attacks, mechanical failures and other events beyond our control. These eventsregulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in an injury, loss of life, or property damage or destruction, as well as a curtailment or interruption in our operations. In addition, third-party damage, mechanical malfunctions, undetected leaks in pipelines, faulty measurement or other errors may result in significanthigher costs or lost revenues.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and exclusions from coverage may limitinterfere with our ability to recoversuccessfully conduct our business.

Any substantial increase in the amount of the full loss in all situations. As a result of market conditions, premiums and deductibles for certain ofnonpayment and/or nonperformance by our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

There can be no assurance that insurance will cover allour joint ventures' customers or any damages and losses resulting from these types of hazards. We are not fully insured against all risks incident to our business and therefore, we self-insure certain risks. We are not insured against all environmental accidents that might occur, other than limited coverage for certain third party sudden and accidental claims. Our property insurance includes business interruption coverage for lost profit arising from physical damage to our facilities. If a significant accident or event occurs that is self-insured or not fully insured, our operations could be temporarily or permanently impaired, our liabilities and expenses could be significant and itvendors could have a material adverse effect on our financial position. Because of our distribution policy, we do not have the same flexibility as other legal entities to accumulate cash to protect against underinsured or uninsured losses.

Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.

HFC, Delek and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals.



We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications. In addition, we could be required to make substantial expenditures in the event of any changes in product quality specifications.

A significant portion of our operating responsibility on refined product pipelines is to ensure the quality and purity of the products loaded at our loading racks. If our quality control measures fail, off-specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages caused by the off-specification fuel or could impact our ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.


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In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various federal, state and local agenciescounterparties, including HF Sinclair, have the authorityagreed to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, requireindemnify us, to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products pipeline system could reduce or eliminate our ability to blend products.

Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.

One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. For example, pipeline construction projects requiring federal approvals are generally subject to certain limitations, for:

•certain pre-closing environmental review requirements under the National Environmental Policy Act, and must also comply with other natural resource review requirements imposed pursuant to the Endangered Species Act and the National Historic Preservation Act. These projects may not be completed on schedule (or at all) or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period ofliabilities discovered within specified time and we will not receive any material increases in revenues untilperiods after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

Rate regulation, changes to rate-making rules, or a successful challenge to the rates we charge may reduce our revenues and the amount of cash we generate.

The FERC regulates the tariff rates for interstate movements and state regulatory authorities regulate the tariff rates for intrastate movements on our pipeline systems. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services.

The primary rate-making methodology of the FERC is price indexing. We use this methodology in all of our interstate markets. The indexing method allows a pipeline to increase its rates based on a percentage change in the PPI for finished goods. If the index falls, we will be required to reduce our rates that are based on the FERC's price indexing methodology if they exceed the new maximum allowable rate. If the FERC price indexing methodology permits a rate increase that is not large enough to fully reflect actual increases in our costs, we may need to file for a rate increase using an alternative method with a much higher burden of proof and without the guarantee of success. These FERC rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. On October 20, 2016, the FERC issued an Advance Notice of Proposed Rulemaking regarding Revisions to Indexing Policies and Page 700 of FERC Form No. 6, 157 FERC ¶ 61, 047 (2016) (“ANOPR”). If final rules are implemented as proposed in that ANOPR, such rules would create new tests for whether our pipelines providing service subject to FERC tariffs could increase rates in accordance with the FERC index in a given year and could restrict our ability to increase our rates as a result, in addition to increasing our annual reporting burdens and the associated costs. Any of the foregoing would adversely affect our revenues and cash flow.

If a party with an economic interest were to file either a protest of our proposal for increased rates or a complaint against our existing tariff rates, or the FERC were to initiate an investigation of our existing rates, then our rates could be subject to detailed review. If our proposed rate increases were found to be in excess of levels justified by our cost of service, the FERC could order us to reduce our rates, and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our


existing rates were found to be in excess of our cost of services, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. Also relevant to our rates and cost of service, on December 15, 2016, the FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs, 157 FERC ¶ 61,210 (2016) (the “NOI”). The NOI sought comments on how the FERC should address any double recovery for partnership pipelines resultingapplicable acquisition;
•certain matters arising from the FERC’s current income tax allowancepre-closing ownership and rateoperation of return policies. Ifassets; and
•ongoing remediation related to the NOIassets.

Our business, results in final regulations or policy changes that alter the FERC’s current approach to liquids pipeline ratemaking and the relevant components of our interstate pipeline transportation rates, those changes could require us to change our rate design and potentially lower our rates. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues andoperation, cash flows if additional volumes and/or capacity are unavailable to offset such rate reductions.

HFC and Delek have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements; however, other current or future shippers may still challenge our tariff rates.

Terrorist attacks (including cyber-attacks), and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued global hostilities or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is unknown. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Uncertainty surrounding continued global hostilities or other sustained military campaigns, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror, may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products.

Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital includingmake cash distributions to our ability to repay or refinance debt.

The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events.  These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operationsunitholders could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decreaseadversely affected in revenues, increased coststhe future if third parties fail to respond or other financial loss, damagesatisfy an indemnification obligation owed to reputation, increased regulation or litigation and or inaccurate information reported from our operations.  These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.us.


Adverse changes in our and/or our general partner's credit ratings and risk profile may negatively affect us.


Our ability to access capital markets is important to our ability to operate our business. Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating.


We are in compliance with all covenants or other requirements set forth in our Credit Agreement. Further, we do not have any rating downgrade triggers that would automatically accelerate the maturity dates of any debt.


While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could affect adversely our ability to borrow on, renew existing, or obtain access to new financing arrangements, could increase the cost of such financing arrangements, could reduce our level of capital expenditures and could impact our future earnings and cash flows.


The credit and business risk profiles of our general partner, and of HFCHF Sinclair as the indirect owner of our general partner, may be factors in credit evaluations of us as a master limited partnership due to the significant influence of our general partner and its indirect ownerownership over our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.



We may be unsuccessful in integrating the operations of the assets we have acquired or may acquire with our operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of completed or future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them, and new geographic areas and the diversion of management's attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.

We own certain of our systems through joint ventures, and our control of such systems is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures.

Although our subsidiary is the operator of the UNEV pipeline and we own a majority interest in the joint venture that owns the UNEV pipeline, the joint venture agreement for the UNEV pipeline generally requires consent of our joint venture partner(s) for specified extraordinary transactions, such as reversing the flow of the pipeline or increasing the fees paid to our subsidiary pursuant to the operating agreement. 

In addition, certain of our systems are operated by joint venture entities that we do not operate, or in which we do not have an ownership stake that permits us to control the business activities of the entity. We have limited ability to influence the business decisions of such joint venture entities.

Because we have partial ownership in the joint ventures, we may be unable to control the amount of cash we will receive from the operation and could be required to contribute significant cash to fund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.

If we are unable to complete capital projects at their expected costs or in a timely manner, if we incur increased maintenance or repair costs on assets, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and increased maintenance or repair expenditures on our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of numerous factors, such as:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project's debt or equity financing costs; and/or
nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

If we are unable to complete capital projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flows could be materially and adversely affected.

We do not own all of the land on which our pipeline systems and other assets are located, which could result in disruptions to our operations. Additionally, a change in the regulations related to a state’s use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects. Finally, certain of our assets are located on tribal lands.

We do not own all of the land on which our pipeline systems and other assets are located, and we are, therefore, subject to the risk of increased costs or more burdensome terms to maintain necessary land use. We obtain the right to construct and operate pipelines


and other assets on land owned by third parties and government agencies for specified periods. If we were to lose these rights through an inability to renew leases, right-of-way contracts or similar agreements, we may be required to relocate our pipelines or other assets and our business could be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-way or leases or to renew existing rights-of-way or leases. If the cost of obtaining or renewing such agreements increases, it may adversely affect our operations and the cash flows available for distribution to unitholders.

The adoption or amendment of laws and regulations that limit or eliminate a state’s ability to exercise eminent domain over private property in a state in which we operate could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects.

Certain of our pipelines are located on Native American tribal lands. Various federal agencies, along with each Native American tribe, promulgate and enforce regulations, including environmental standards, regarding operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations (including various taxes, fees, and other requirements and conditions) and to grant approvals independent from federal, state and local statutes and regulations. Following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Native American landowner, bars condemnation of any interest in the allotment.  Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operations.  These factors may increase our cost of doing business on Native American tribal lands.

Our business may suffer due to a change in the composition of our Board of Directors, if any of our key senior executives or other key employees who provide services to us discontinue employment, or if certain of our executive officers, who also allocate time to our general partner and its affiliates, do not have enough time to dedicate to our business. Furthermore, a shortage of skilled labor or disruptions in the labor force that provides services to us may make it difficult for us to maintain labor productivity.

Our future success depends to a large extent on the services of HLS's Board of Directors, key senior executives and key senior employees who provide services to us. Also, our business depends on the continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks.
Our general partner shares officers and administrative personnel with HFC to operate both our business and HFC's business. These officers face conflicts regarding the allocation of their and other employees' time, which may affect adversely our results of operations, cash flows and financial condition.

A portion of HFC's employees that are seconded to us from time to time are represented by labor unions under collective bargaining agreements with various expiration dates. HFC may not be able to renegotiate the collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, existing labor agreements may not prevent a future strike or work stoppage, and any work stoppage could negatively affect our results of operations and financial condition.



RISKS TO COMMON UNITHOLDERS


HFCHF Sinclair and its affiliates may have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.


Currently, HFC indirectly ownsHF Sinclair and certain of its subsidiaries collectively own a 57%47% limited partner interest and a non-economic general partner interest in us and controls HLS, the general partner of our general partner, HEP Logistics. Conflicts of interest may arise between HFCHF Sinclair and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its other affiliates over our interests. These conflicts include, among others, the following situations:




HFC,•HF Sinclair, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm's-length,arm's -length, third-party transactions;
neither our partnership agreement nor any other agreement requires HFC to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. HFC's•HF Sinclair's directors and officers have a fiduciary duty to make thesebusiness decisions in the best interests of the stockholders of HFC;HF Sinclair;
•our general partner is allowed to take into account the interests of parties other than us, such as HFC,HF Sinclair, in resolving conflicts of interest;
•our partnership agreement provides for modified or reduced fiduciary duties for our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
•our general partner determines which costs incurred by HFCHF Sinclair and its affiliates are reimbursable by us;
•our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
•our general partner may, in some circumstances, cause us to borrow funds to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or affiliates;
•our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash available to us; and
•our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with HFC.HF Sinclair.


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Cost reimbursements, which will be determined by our general partner, and fees due to our general partner and its affiliates for services provided, are substantial.


Under our Omnibus Agreement, we are obligated to pay HFCHF Sinclair an administrative fee of currently $2.5$5.0 million per year for the provision by HFCHF Sinclair or its affiliates of various general and administrative services for our benefit. Beginning July 1, 2018, theThe administrative fee will beis subject to an annual upward adjustment for changes in PPI. In addition, we are required to reimburse HFCHF Sinclair pursuant to the secondment arrangement for the wages, benefits, and other costs of HFCHF Sinclair employees seconded to HLS to perform services at certain of our processing, refining, pipeline and tankage assets. We can neither provide assurance that HFCHF Sinclair will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If HFCHF Sinclair fails to provide us with adequate personnel, our operations could be adversely impacted.


The administrative fee and secondment allocations are subject to annual review and may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from HFCHF Sinclair or its affiliates. For example, in connection with the HEP Transaction, we paid HF Sinclair a temporary monthly fee of $62,500 through November 30, 2022 relating to transition services provided to us by HF Sinclair. Our general partner will determine the amount of general and administrative expenses that will be allocated to us in accordance with the terms of our partnership agreement. In addition, our general partner and its affiliates are entitled to reimbursement for all other expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees of HLS who provide services to us.


Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf, plus the administrative fee. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we are charged fees as determined by our general partner.


Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, fund expansion capital expenditures, or for other purposes.


As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, fund expansion capital expenditures or for other purposes. If we then issue additional equity at a significantly lower price, material dilution to our existing unitholders could result.




Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.


Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of HLS and have no right to do so on an annual or other continuing basis. The board of directors of HLS is chosen by the sole member of HLS. If unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.


The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Unitholders will be unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to prevent its removal. Unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding (other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner's general partner) cannot vote on any matter; however, no such person currently exists. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings, acquire information about our operations, and influence the manner or direction of management.

The control of our general partner may be transferred to a third party without unitholder consent.


Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their respective partnership interests in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner of our general partner with their own choices and to control the decisions made by the board of directors and officers.

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We may issue additional limited partner units without unitholder approval, which would dilute an existing unitholder's ownership interests.


Under our partnership agreement, provided there is no significant decrease in our operating performance, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and HEP currently has a shelf registration on file with the SEC pursuant to which it may issue up to $2.0 billion in additional common units. On May 10, 2016, HEP established a continuous offering program under the shelf registration statement pursuant to which HEP may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. As of December 31, 2017,2022, HEP has issued 2.22.4 million units under this program for gross consideration of $77$82.3 million. No units were issued under the program during the year ended December 31, 2022.


The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•our unitholders' proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of the common units may decline.


Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.


In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to unitholders.


Our partnership agreement requires us to distribute all available cash to our unitholders; however, it also requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available to make the required payments to our debt holders or to pay the minimum quarterly distributiondistributions on our common units every quarter.




HFCHF Sinclair and its affiliates may engage in limited competition with us.


HFCHF Sinclair and its affiliates may engage in limited competition with us. Pursuant to the Omnibus Agreement, HFCHF Sinclair and its affiliates agreed not to engage in the business of operating intermediate or refined product pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. The Omnibus Agreement, however, does not apply to:

•any business operated by HFCHF Sinclair or any of its subsidiaries at the closing of our initial public offering;
•any business or asset that HFCHF Sinclair or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5 million; and
•any business or asset that HFCHF Sinclair or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.


In the event that HFCHF Sinclair or its affiliates no longer control our partnership or there is a change of control of HFC,HF Sinclair, the non-competition provisions of the Omnibus Agreement will terminate.


Our general partner has a limited call right that may require a unitholder to sell its common units at an undesirable time or price.


If at any time our general partner and its affiliates own more than 80% of the common units (which it does not presently), our general partner will have the right (which it may assign to any of its affiliates or to us) but not the obligation to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, a holder of common units may be required to sell its units at a time or price that is undesirable to it and may not receive any return on its investment. A common unitholder may also incur a tax liability upon a sale of its units.


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A unitholder may not have limited liability if a court finds that unitholder actions constitute control of our business or that we have not complied with state partnership law.


Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.


In addition, Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.


Further, we conduct business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. The unitholders might be held liable for the partnership's obligations as if they were a general partner if a court or government agency determined that we were conducting business in the state but had not complied with the state's partnership statute.


HFCHF Sinclair and our other significant unitholders may sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of theour common units. Additionally, HFCHF Sinclair may pledge or hypothecate its common units or its interest in us.


HFC currently holdsAs of February 15, 2023, HF Sinclair held 59,630,030 of our common units and REH Company, our next largest unitholder, held 21,000,000 of our common units, which is approximately 57%47% and 16.6% of our outstanding common units.units, respectively. The sale of these common units (or the perception that these sales may occur) in the public or private markets by HF Sinclair or REH Company could have an adverse impact on the trading price of our common units. Additionally, we agreed to provide HFCboth HF Sinclair and REH Company registration rights with respect to our common units that it holds. HFCthey hold. HF Sinclair may pledge or hypothecate its common units, and such pledge or hypothecation may include terms and conditions that might result in an adverse impact on the trading price of our common units.



TAX RISKS TO COMMON UNITHOLDERS


Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as usand not being subject to a material amount of entity-level taxation by individual states. If the U.S. Internal Revenue Service (the “IRS”)IRS were to


treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to additional amounts of entity-level taxation for federal or state tax purposes, our cash available for distribution to our unitholders wouldcould be substantially reduced.


The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.


Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income"“qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.


If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, our treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our common units.


At the entity level, wereif we to bewere subject to U.S. federal income tax, we would also be subject to the income tax provisions of many states. Moreover, states are evaluating ways to independently subject partnerships to entity-level taxation through the imposition of state income taxes, franchise taxes and other forms of taxation. For example, we are required to pay Texas margin tax on any income apportioned to Texas.Texas, despite our status as a partnership. Imposition of any additional such taxes on us or an increase in the existing tax rates wouldcould reduce the cash available for distributions to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.


The present U.S. federal income tax treatment of publicly traded partnerships including us, or an investment in our common units may be modified by administrative, legislative or judicial changes and differing interpretations at any time. From time to time, membersMembers of Congress proposehave frequently proposed and considerconsidered similar substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. AlthoughThere can be no assurance that there is no current legislative proposal, a prior legislative proposal would have eliminatedwill not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income exceptionrules in a manner that could impact our ability to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatmentqualify as a partnership for federal income tax purposes.

We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changesin the future, which could also negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws and interpretations thereof may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any changes or proposals will ultimately be enacted. You are urged to consult with your own tax advisor with respect to the status of legislative, regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

On January 24, 2017, the U.S. Treasury Department and the IRS published final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for federal income tax purposes.


If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.


The IRS may adopt positions that differ from the positions we have taken or may take on tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. Atake, and a court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS willwould be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.


If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit


adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced, and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on their behalf.


Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Under our partnership agreement, our general partner is permitted to make elections under the newthese rules to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each affected current and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our affected current and former unitholders take such audit adjustment into account and pay any resulting taxes (including any applicable penalties and interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties andor interest, our cash available for distribution to our unitholders might be substantially reduced, and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on their behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.


Even if youunitholders do not receive any cash distributions from us, youthey will be required to pay taxes on yourtheir share of our taxable income.


YouUnitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on yourtheir share of our taxable income, whether or not youthey receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, youunitholders may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to you as taxable income without any increase in our cash available for distribution. YouUnitholders may not receive cash distributions from us equal to yourtheir share of our taxable income or even equal to the actual tax due from youthe unitholder with respect to that income.

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Tax gain or loss on the disposition of our common units could be more or less than expected.


If a unitholder disposes of common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income result in a decrease of the unitholder's tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.


A substantial portion of the amount realized from the sale of a unitholder's common units, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. Thus, the unitholder may recognize both ordinary income and capital loss from the sale of such units if the amount realized on a sale of such units is less than the unitholder's adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which the unitholder sells hisits units, the unitholder may recognize ordinary income from our allocations of income and gain to the unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.


Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we
We are generally entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. income.

If thisour business interest is subject to limitation were to apply with respect to a taxable year,under these rules, it could result in an increase in the taxable income allocable to a unitholder for such taxable year without any corresponding increase in the cash available for distribution to such unitholder.



Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to U.S. income tax filing requirements on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected”effectively connected with a U.S. trade or business. As a result, distributions to a Non-U.S.non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate, and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
The Tax Cuts and Jobs Act imposes In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding obligationtax on the amount of 10%any distribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the amount realized uponcalculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder’s sale or exchangeunitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business. However, duebusiness is generally required to challengeswithhold 10% of administeringthe “amount realized” by the transferor unless the transferor certifies that it is not a withholding obligation applicable to open market trading and other complications,foreign person. While the IRS has temporarily suspendeddetermination of a partner’s amount realized generally includes any decrease of a partner’s share of the applicationpartnership’s liabilities, the Treasury Regulations provide that the amount realized on a transfer of this withholding rule to open market transfers ofan interest in a publicly traded partnerships pending promulgationpartnership, such as our common units, will generally be the amount of regulations or other guidance that resolvesgross proceeds paid to the challenges. It is not clear if or when such regulations or other guidancebroker effecting the applicable transfer on behalf of the transferor, and thus will be issued. Non-U.S.determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Current and prospective foreign unitholders should consult atheir tax advisor before investingadvisors regarding the impact of these rules on an investment in our common units.
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We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.


Because we cannot match transferors and transferees of common units, and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholders' sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.adjustments.


We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.


We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (the "Allocation Date") based upon the ownership of our units on the first day of each month (the “Allocation Date”) instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. The U.S. Department of the Treasury adopted final Treasury Regulations allowingallow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.




A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, it would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.


Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.


Unitholders likely will be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.


In addition to U.S. federal income taxes,tax, unitholders likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future. Unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions, even if they do not live in these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma, Washington, Kansas, Wyoming and Nevada. Wemultiple states. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own propertyassets or conduct business in otheradditional states or foreign countries inthat impose a personal income tax. Unitholders should consult with their own tax advisors regarding the future. It isfiling of such tax returns, the unitholder's responsibility to file all federal, state, localpayment of such taxes, and foreign tax returns.the deductibility of any taxes paid.





Item 1B.Unresolved Staff Comments
Item 1B.Unresolved Staff Comments
We do not have any unresolved SEC staff comments.



Item 3.Legal Proceedings
We are aItem 3.Legal Proceedings
In the ordinary course of business, we may become party to various legal, regulatory or administrative proceedings or governmental investigations, including environmental and regulatory proceedings.other matters. Damages or penalties may be sought from us in some matters and certain matters may require years to resolve. While the outcome and impact of these proceedings and investigations on us cannot be predicted with certainty, based on advice of counsel, management believes that the resolution of these legal proceedings
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and regulatory proceedingsinvestigations, through settlement or adverse judgment, will not, either individually or in the aggregate, have a materiallymaterial adverse effect on our financial condition, results of operations or cash flows.



Item 4.Mine Safety Disclosures
Item 4.Mine Safety Disclosures
Not applicable.

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PART II
 
Item 5.Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Item 5.Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Our common limited partner units are traded on the New York Stock Exchange under the symbol “HEP.” The following table sets forth the range of the daily high and low sales prices per common unit, cash distributions per common unit and the trading volume of common units for the periods indicated.
Years Ended December 31, High Low 
Cash
Distributions
 
Trading
Volume
2017        
Fourth quarter $35.84
 $31.56
 $0.6500
 9,662,789
Third quarter $36.05
 $30.11
 $0.6450
 16,750,589
Second quarter $37.56
 $30.36
 $0.6325
 8,644,252
First quarter $38.09
 $32.06
 $0.6200
 8,883,617
2016        
Fourth quarter $34.87
 $29.53
 $0.6075
 7,029,100
Third quarter $36.98
 $31.30
 $0.5950
 6,599,800
Second quarter $36.99
 $31.75
 $0.5850
 8,201,400
First quarter $34.50
 $21.44
 $0.5750
 11,258,800
 
The cash distribution for the fourth quarter of 2017 was declared on January 26, 2018, and paid on February 14, 2018, to all unitholders of record on February 5, 2018.

As of February 13, 2018,15, 2023, we had approximately 19,65016,748 common unitholders, including beneficial owners of common units held in street name.


We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. See “Liquidity and Capital Resources” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of conditions and limitations prohibiting distributions under the Credit Agreement and indentures relating to our senior notes.

Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.


Common Unit Repurchases Made in the Quarter


The following table discloses purchases of our common units made by us or on our behalf for the periods shown below:
PeriodTotal Number of
Units Purchased		Average Price
Paid Per Unit		Total Number of
Units Purchased as
Part of Publicly
Announced Plan or
Program		Maximum Number
of Units that May
Yet be Purchased
Under a Publicly
Announced Plan or
Program
October 2022— $— — $— 
November 202272,831 $19.12 — $— 
December 202222,409 $18.71 — $— 
Total for October to December 202295,240 — 
Period 
Total Number of
Units Purchased
 
Average Price
Paid Per Unit
 
Total Number of
Units Purchased as
Part of Publicly
Announced Plan or
Program
 
Maximum Number
of Units that May
Yet be Purchased
Under a Publicly
Announced Plan or
Program
October 2017 —
 $—
 —
 $—
November 2017 —
 $—
 —
 $—
December 2017 16,818
 $33.90
 —
 $—
Total for October to December 2017 16,818
   —
  


The units reported represent (a) purchases of 72,831 common units in the open market for delivery to the recipients of our phantom unit and performance unit awards under our Long-Term Incentive Plan at the time of grant or settlement, as applicable; and (b) the delivery of 16,81822,409 common units (which units were previously issued to certain officers and other employees pursuant to restrictedphantom unit awards at the time of grant)grant or settlement, as applicable) by such officers and employees to provide funds for the payment of payroll and income taxes due at vesting in the case of officers and employees who did not elect to satisfy such taxes by other means.





We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The units reported represent common units purchased in the open market for delivery to recipients of our restricted unit and performance unit awards under our Long-Term Incentive Plan at the time of grant or settlement, as applicable.




Item 6.Selected Financial Data

The following table shows selected financial information from the consolidated financial statements of HEP and from the financial statements of our Predecessor (defined below). We acquired assets from HFC, including El Dorado Operating on November 1, 2015, crude tanks at HFC's Tulsa refinery on March 31, 2016 and Woods Cross Operating on October 1, 2016. As we are a variable interest entity controlled by HFC, these acquisitions were accounted for as transfers between entities under common control. Accordingly, this financial data includes 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 2 in notes to consolidated financial statements of HEP for further discussion of these acquisitions.

This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of HEP and related notes thereto included elsewhere in this Form 10-K.



6.[Reserved]
  Years Ended December 31,
  2017 2016 2015 2014 2013
  (In thousands, except per unit data)
Statement of Income Data:          
Revenues $454,362
 $402,043
 $358,875
 $332,545
 $305,182
Operating costs and expenses          
Operations (exclusive of depreciation and amortization) 137,605
 123,986
 105,556
 106,185
 100,131
Depreciation and amortization 79,278
 70,428
 63,306
 62,529
 65,783
General and administrative 14,323
 12,532
 12,556
 10,824
 11,749
  231,206
 206,946
 181,418
 179,538
 177,663
Operating income 223,156
 195,097
 177,457
 153,007
 127,519
Equity in earnings of equity method investments 12,510
 14,213
 4,803
 2,987
 2,826
Interest expense (58,448) (52,552) (37,418) (36,101) (47,010)
Interest income 491
 440
 526
 3
 161
Loss on early extinguishments of debt (12,225) —
 —
 (7,677) —
Remeasurement gain on preexisting equity interests 36,254
 —
 —
 —
 —
Gain on sale of assets and other 422
 677
 486
 82
 1,871
  (20,996) (37,222) (31,603) (40,706) (42,152)
Income before income taxes 202,160
 157,875
 145,854
 112,301
 85,367
State income tax expense (249) (285) (228) (235) (333)
Net income 201,911
 157,590
 145,626
 112,066
 85,034
Allocation of net loss attributable to Predecessor —
 10,657
 2,702
 1,747
 1,047
Allocation of net income attributable to noncontrolling interests (6,871) (10,006) (11,120) (8,288) (6,632)
Net income attributable to the partners 195,040
 158,241
 137,208
 105,525
 79,449
General partner interest in net income, including incentive distributions(1)
 (35,047) (57,173) (42,337) (34,667) (27,523)
Limited partners’ interest in net income $159,993
 $101,068
 $94,871
 $70,858
 $51,926
Limited partners’ earnings per unit – basic and diluted(1)
 $2.28
 $1.69
 $1.60
 $1.20
 $0.88
Distributions per limited partner unit $2.5475
 $2.3625
 $2.2025
 $2.0750
 $1.9550
           
Other Financial Data:          
Cash flows from operating activities $238,487
 $243,548
 $231,442
 $185,256
 $182,393
Cash flows from investing activities $(286,273) $(143,030) $(246,680) $(198,423) $(90,704)
Cash flows from financing activities $51,905
 $(111,874) $27,421
 $9,645
 $(90,574)
EBITDA(2)
 $344,749
 $277,545
 $237,180
 $211,701
 $192,054
Distributable cash flow(3)
 $242,955
 $218,810
 $197,046
 $172,718
 $146,579
Maintenance capital expenditures(4)
 $7,748
 $9,658
 $8,926
 $4,616
 $8,683
Expansion capital expenditures 37,062
 50,046
 30,467
 75,343
 43,418
Acquisition capital expenditures 245,446
 44,119
 153,728
 118,727
 41,635
Total capital expenditures $290,256
 $103,823
 $193,121
 $198,686
 $93,736
           
Balance Sheet Data (at period end):          
Net property, plant and equipment $1,569,471
 $1,328,395
 $1,293,060
 $1,163,631
 $1,018,854
Total assets $2,154,114
 $1,884,237
 $1,777,646
 $1,584,114
 $1,442,573
Long-term debt(5)
 $1,507,308
 $1,243,912
 $1,008,752
 $866,986
 $806,655
Total liabilities $1,669,049
 $1,412,446
 $1,151,424
 $989,324
 $914,656
Total equity(6)
 $485,065
 $471,791
 $626,222
 $594,790
 $527,917
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(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 included incentive distributions that were 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. As a result of the IDR restructuring transaction, no IDR or general partner distributions were made after October 31, 2017. See "Business and Properties - Overview."

(2)Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to Holly Energy Partners plus (i) interest expense net of interest income and loss on early extinguishment of debt, (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 HEP 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.
  Years Ended December 31,
  2017 2016 2015 2014 2013
  (In thousands)
Net income attributable to the partners $195,040
 $158,241
 $137,208
 $105,525
 $79,449
Add (subtract):          
Interest expense 55,385
 49,306
 35,490
 34,280
 44,041
Interest income (491) (440) (526) (3) (161)
Amortization of discount and deferred debt issuance costs 3,063
 3,246
 1,928
 1,821
 2,120
Loss on early extinguishment of debt 12,225
 —
 —
 7,677
 —
Amortization of unrealized loss attributable to discontinued cash flow hedge —
 —
 —
 —
 849
State income tax expense 249
 285
 228
 235
 333
Depreciation and amortization 79,278
 70,428
 63,306
 62,529
 65,783
Predecessor depreciation and amortization —
 (3,521) (454) (363) (360)
EBITDA $344,749
 $277,545
 $237,180
 $211,701
 $192,054

(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 exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.



Set forth below is our calculation of distributable cash flow.
  Years Ended December 31,
  2017 2016 2015 2014 2013
  (In thousands)
Net income attributable to the partners $195,040
 $158,241
 $137,208
 $105,525
 $79,449
Add (subtract):          
Depreciation and amortization 79,278
 70,428
 63,306
 62,529
 65,783
Remeasurement gain on preexisting equity interests (36,254) —
 —
 —
 —
Amortization of discount and deferred debt issuance costs 3,063
 3,246
 1,928
 1,821
 2,120
Amortization of unrealized loss attributable to discontinued cash flow hedge —
 —
 —
 —
 849
Loss on early extinguishment of debt 12,225
 —
 —
 7,677
 —
Increase (decrease) in deferred revenue related to minimum revenue commitments (1,283) (1,292) (1,233) (2,503) 3,686
Maintenance capital expenditures (4)
 (7,748) (9,658) (8,926) (4,616) (8,683)
Crude revenue settlement —
 —
 —
 —
 918
Increase (decrease) in environmental liability (581) (584) 1,107
 1,596
 619
Increase (decrease) in reimbursable deferred revenue (3,679) (2,733) 176
 (2,274) (1,642)
Other non-cash adjustments 2,894
 4,683
 3,934
 3,326
 3,840
Predecessor depreciation and amortization —
 (3,521) (454) (363) (360)
Distributable cash flow $242,955
 $218,810
 $197,046
 $172,718
 $146,579


(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)Includes $1,012 million, $553 million, $712 million, $571 million and $363 million in Credit Agreement advances that were classified as long-term debt at December 31, 2017, 2016, 2015, 2014 and 2013, respectively.

(6)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 partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to HEP. Additionally, if the assets contributed and acquired from HFC while we were a consolidated variable interest entity 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.




Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7, including but not limited to the sections onunder “Results of Operations” and “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I and Item 1A. “Risk Factors.” In this document, the words “we,” “our,” “ours” and “us” refer to HEPHolly Energy Partners, L.P. (“HEP”) and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.


References herein to HEP with respect to time periods prior to March 14, 2022, include HEP and its consolidated subsidiaries and do not include Sinclair Transportation Company LLC (“Sinclair Transportation”) and its consolidated subsidiaries (collectively, the “HEP Acquired Sinclair Businesses”). References herein to HEP with respect to time periods from and after March 14, 2022 include the operations of the HEP Acquired Sinclair Businesses.

References herein to HF Sinclair Corporation (“HF Sinclair”) with respect to time periods prior to March 14, 2022 refer to HollyFrontier Corporation (“HFC”) and its consolidated subsidiaries and do not include Hippo Holding LLC (now known as Sinclair Holding LLC), Sinclair Transportation or their respective consolidated subsidiaries (collectively, the “HFS Acquired Sinclair Businesses”). References herein to HF Sinclair with respect to time periods from and after March 14, 2022 refer to HF Sinclair and its consolidated subsidiaries, which include the operations of the combined business operations of HFC and the HFS Acquired Sinclair Businesses.

OVERVIEW


HEP, together with its consolidated subsidiaries, is a Delawarepublicly held master limited partnership. WeOn March 14, 2022 (the “Closing Date”), HFC and HEP announced the establishment of HF Sinclair, as the new parent holding company of HFC and HEP and their subsidiaries, and the completion of their respective acquisitions of Sinclair Oil Corporation (now known as Sinclair Oil LLC ("Sinclair Oil")) and Sinclair Transportation from REH Company (formerly known as The Sinclair Companies, and referred to herein as “REH Company”). On the Closing Date, HF Sinclair completed its acquisition of Sinclair Oil by effecting (a) a holding company merger with HFC surviving such merger as a direct wholly owned subsidiary of HF Sinclair (the “HFC Merger”), and (b) immediately following the HFC Merger, a contribution whereby REH Company contributed all of the equity interests of Hippo Holding LLC (now known as Sinclair Holding LLC), the parent company of Sinclair Oil (the “Target Company”), to HF Sinclair in exchange for shares of HF Sinclair, resulting in the Target Company becoming a direct wholly owned subsidiary of HF Sinclair (together with the HFC Merger, the “HFC Transactions”).

As of December 31, 2022, HF Sinclair and its subsidiaries owned a 47% limited partner interest and the non-economic general partner interest in HEP.

Additionally, on the Closing Date and immediately prior to consummation of the HFC Transactions, HEP acquired all of the outstanding equity interests of Sinclair Transportation from REH Company in exchange for 21 million newly issued common limited partner units of HEP (the “HEP Units”), representing 16.6% of the pro forma outstanding HEP Units with a value of approximately $349 million based on HEP’s fully diluted common limited partner units outstanding and closing unit price on March 11, 2022, and cash consideration equal to $329.0 million, inclusive of final working capital adjustments for an aggregate transaction value of $678.0 million (the “HEP Transaction” and together with the HFC Transactions, the “Sinclair Transactions”). The cash consideration was funded through a draw under HEP’s senior secured revolving credit facility. The HEP Transaction was conditioned on the closing of the HFC Transactions, which occurred immediately following the HEP Transaction.

Sinclair Transportation, together with its subsidiaries, owned REH Company’s integrated crude and refined products pipelines and terminal assets, including approximately 1,200 miles of integrated crude and refined product pipeline supporting the REH Company refineries and other third-party refineries, eight product terminals and two crude terminals with approximately 4.5 million barrels of operated storage. In addition, HEP acquired Sinclair Transportation’s interests in three pipeline joint ventures for crude gathering and product offtake including: Saddle Butte Pipeline III, LLC (25.06% non-operated interest); Pioneer Investments Corp. (49.995% non-operated interest); and UNEV Pipeline, LLC ("UNEV") (the 25% non-operated interest not already owned by HEP, resulting in UNEV becoming a wholly owned subsidiary of HEP).

See Notes 1 and 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements” for additional information regarding the acquisitions.

Through 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 HFCHF Sinclair and other refineries in the Mid-Continent, Southwest and Northwest regions of the United States and Delek’s refinery in Big Spring, Texas.States. HEP, through its
- 52 -

subsidiaries and joint ventures, owns and/or operates petroleum product and crude pipelines, tankage and terminals in Texas,Colorado, Idaho, Iowa, Kansas, Missouri, Nevada, New Mexico, Arizona,Oklahoma, Texas, Utah, Washington Idaho, Oklahoma, Utah, Nevada,and Wyoming and Kansas as well as refinery processing units in Utah and Kansas. HFC owned 59% of our outstanding common units and the non-economic general partner interest as of December 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 obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in a non-monetary exchange for a 20-year terminalling services agreement, whereby, a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Osage is the owner of the Osage pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. The Osage pipeline is the primary pipeline that supplies HFC's El Dorado Refinery with crude oil.Market Developments

Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we also agreed to build two connections on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange, we are the named operator of the Osage pipeline and transitioned into this role on September 1, 2016.

On March 31, 2016, we acquired crude oil tanks located at HFC’s Tulsa refinery from an affiliate of Plains for $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accountedOur results for the transaction as a financing arrangement. Accordingly, the tanks remained on HFC’s balance sheetyear ended December 31, 2022 were favorably impacted by global demand for transportation fuels, lubricants and were depreciated for accounting purposes.

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 cashtransportation and terminal services having returned to Cheyenne Pipeline LLC. Cheyenne Pipeline LLCpre-pandemic levels. We expect our customers will continue to be operatedadjust refinery production levels commensurate with market demand. The extent to which HEP’s future results are affected by an affiliatethe COVID-19 pandemic or volatile regional and global economic conditions will depend on various factors and consequences beyond our control. However, we have long-term customer contracts with minimum volume commitments, which have expiration dates from 2023 to 2037. These minimum volume commitments accounted for approximately 70% of our total tariffs and fees billed to customers for both the years ended December 31, 2022 and 2021. We are currently not aware of Plains, which ownsany reasons that would prevent such customers from making the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramieminimum payments required under the contracts or potentially making payments in excess of the minimum payments. In addition to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.these payments, we also expect to collect payments for services provided to uncommitted shippers.

Investment in Joint Venture
On October 1, 2016, we acquired all the membership interests of Woods Cross Operating,2, 2019, HEP Cushing LLC (“HEP Cushing”), a wholly owned subsidiary of HFC, which ownsHEP, and Plains Marketing, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for (i) the newly constructed atmospheric distillation tower, fluid catalytic cracking unit,development, construction, ownership and polymerization unit locatedoperation of a new 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that connected the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HF Sinclair 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 HFC’s Woods Cross refinery for cash considerationthe end of $278 million. In connection with this transaction, wethe third quarter of 2021. Long-term commercial agreements have been entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC that provide minimum annualized revenuesto support the Cushing Connect Joint Venture assets.

The Cushing Connect Joint Venture contracted with an affiliate of $57 million asHEP to manage the construction and operation of the acquisition date.


We are a consolidated variable interest entityCushing Connect Pipeline and with an affiliate of HFC. Therefore,Plains to manage the acquisitionsoperation of the crude tanks at HFC's Tulsa refinery on March 31, 2016, and Woods Cross Operating on October 1, 2016,Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment was generally shared equally among the partners. However, we were accountedsolely responsible for as transfers between entities under common control. Accordingly, this financial data has been retrospectively adjusted to includeany Cushing Connect Pipeline construction costs that exceeded 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 Notes 1 and 2 in the notes to consolidated financial statements of HEP included in this annual report 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 subsidiaries of Plains, for total consideration of $250 million. Prior to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a resultbudget by more than 10%. HEP's share of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.

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

SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminalcost of the FrontierCushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline and from Wahsatch Station. Frontier Aspen isconstruction costs was approximately $74 million, including approximately $5 million of Cushing Connect Pipeline construction costs that exceeded the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.budget by more than 10% borne solely by HEP.


Agreements with HFC and DelekHF Sinclair
We serve HFC'sHF Sinclair's refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from 20192023 to 2036.2037. Under these agreements, HFCHF Sinclair 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 plus 0.78%. FERC received requests for rehearing of its December 17, 2020 order, and on January 20, 2022, FERC revised the index level used to determine annual changes to interstate oil pipeline rate ceilings to Producer Price Index minus 0.21%. The order required the recalculation of the July 1, 2021 index ceilings to be effective as of March 1, 2022. As of December 31, 2017,2022, these agreements with HFC requireHF Sinclair required minimum annualized payments to us of $324$453 million.


- 53 -

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

We have a pipelines and terminals agreement with Delek expiring in 2020 under which Delek has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that is also subject to annual tariff rate adjustments. We also have a capacity lease agreement under which we lease Delek space on our Orla to El Paso pipeline for the shipment of refined product. The terms under this lease agreement expire beginning in 2018 through 2022. As of December 31, 2017, these agreements with Delek require minimum annualized payments to us of $33 million.


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

On June 1, 2020, HFC announced plans to permanently cease petroleum refining operations at its Cheyenne refinery (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 two five-year renewal option periods for HFC’s (and now HF Sinclair’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 (and now HF Sinclair) will pay a base tariff to HEP for available crude oil storage and HFC (and now HF Sinclair) and HEP will split any profits generated on crude oil contango opportunities and (3) HFC paid a $10 million one-time cash payment to HEP for the termination of the existing minimum volume commitment.

Under certain provisions of an omnibus agreement that we have with HFCHF Sinclair (“Omnibus Agreement”), we pay HFCHF Sinclair an annual administrative fee, ($2.5currently $5.0 million in 2017), for the provision by HFCHF Sinclair or its affiliates of various general and administrative services to us. ThisIn connection with the HEP Transaction, we paid HF Sinclair a temporary monthly fee does not includeof $62,500 through November 30, 2022, relating to transition services provided to HEP by HF Sinclair. Neither the annual administrative fee nor the temporary fee includes the salaries of personnel employed by HFCHF Sinclair who perform services for us on behalf of HLS or the cost of their employee benefits, which are separately charged to us by HFC.HF Sinclair. We also reimburse HFCHF Sinclair and its affiliates for direct expenses they incur on our behalf.


Under HLS’s Secondment Agreement with HFC,HF Sinclair, certain employees of HFCHF Sinclair are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFCHF Sinclair 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 (and now HF Sinclair) 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 economic conditions discussed in “Overview - Market Developments” above, we also expect over the longer term to continue to pursue purchases of logistic and other assets at HFC's existing refining locations in New Mexico, Utah, Oklahoma, Kansas and Wyoming. We also expect to work with HFCHF Sinclair on logistic asset acquisitions in conjunction with HFC’sHF Sinclair’s refinery acquisition strategies. See “Overview” above for a discussion of the Sinclair Transactions.

Furthermore, as demonstrated by the HEP Transaction, we plan to continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.




A more detailed discussion of our financial condition at December 31, 2022 and 2021 and operating results for the years ended December 31, 2022, 2021 and 2020 is presented in the following sections.



RESULTS OF OPERATIONS (Unaudited)


Income, Distributable Cash Flow and Volumes
The following tables present income, distributable cash flow and volume information for the years ended December 31, 2017, 20162022, 2021 and 2015. These results have been adjusted2020.
- 54 -

 Years Ended December 31,Change from
 202220212021
 (In thousands, except per unit data)
Revenues
Pipelines:
Affiliates—refined product pipelines$84,535 $69,351 $15,184 
Affiliates—intermediate pipelines32,192 30,101 2,091 
Affiliates—crude pipelines84,026 77,768 6,258 
200,753 177,220 23,533 
Third parties—refined product pipelines28,709 38,064 (9,355)
Third parties—crude pipelines55,989 47,826 8,163 
285,451 263,110 22,341 
Terminals, tanks and loading racks:
Affiliates143,310 124,511 18,799 
Third parties24,502 17,756 6,746 
167,812 142,267 25,545 
Affiliates—refinery processing units94,217 89,118 5,099 
Total revenues547,480 494,495 52,985 
Operating costs and expenses
Operations (exclusive of depreciation and amortization)210,623 170,524 40,099 
Depreciation and amortization99,092 93,800 5,292 
General and administrative17,003 12,637 4,366 
Goodwill impairment— 11,034 (11,034)
326,718 287,995 38,723 
Operating income220,762 206,500 14,262 
Other income (expense):
Equity in earnings (losses) of equity method investments(260)12,432 (12,692)
Interest expense, including amortization(82,560)(53,818)(28,742)
Interest income91,406 29,925 61,481 
Gain on sales-type leases— 24,677 (24,677)
Gain on sale of assets and other668 6,179 (5,511)
9,254 19,395 (10,141)
Income before income taxes230,016 225,895 4,121 
State income tax expense(111)(32)(79)
Net income229,905 225,863 4,042 
Allocation of net income attributable to noncontrolling interests(13,122)(10,917)(2,205)
Net income attributable to the partners$216,783 $214,946 $1,837 
Limited partners’ earnings per unit—basic and diluted$1.77 $2.03 $(0.26)
Weighted average limited partners’ units outstanding122,298 105,440 16,858 
EBITDA (1)
$307,140 $332,671 $(25,531)
Adjusted EBITDA (1)
$415,332 $339,203 $76,129 
Distributable cash flow (2)
$307,489 $269,805 $37,684 
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines143,303 108,767 34,536 
Affiliates—intermediate pipelines129,295 125,225 4,070 
Affiliates—crude pipelines456,797 279,514 177,283 
729,395 513,506 215,889 
Third parties—refined product pipelines38,000 49,356 (11,356)
Third parties—crude pipelines144,478 129,084 15,394 
911,873 691,946 219,927 
Terminals and loading racks:
Affiliates560,038 391,698 168,340 
Third parties38,211 51,184 (12,973)
598,249 442,882 155,367 
Affiliates—refinery processing units70,222 69,628 594 
Total for pipelines, terminals and refinery processing unit assets (bpd)1,580,344 1,204,456 375,888 
- 55 -

 Years Ended December 31,Change from
 202120202020
 (In thousands, except per unit data)
Revenues
Pipelines:
Affiliates—refined product pipelines$69,351 $73,571 $(4,220)
Affiliates—intermediate pipelines30,101 30,023 78 
Affiliates—crude pipelines77,768 80,026 (2,258)
177,220 183,620 (6,400)
Third parties—refined product pipelines38,064 43,371 (5,307)
Third parties—crude pipelines47,826 38,843 8,983 
263,110 265,834 (2,724)
Terminals, tanks and loading racks:
Affiliates124,511 135,867 (11,356)
Third parties17,756 15,825 1,931 
142,267 151,692 (9,425)
Affiliates—refinery processing units89,118 80,322 8,796 
Total revenues494,495 497,848 (3,353)
Operating costs and expenses
Operations (exclusive of depreciation and amortization)170,524 147,692 22,832 
Depreciation and amortization93,800 99,578 (5,778)
General and administrative12,637 9,989 2,648 
Goodwill impairment11,034 35,653 (24,619)
287,995 292,912 (4,917)
Operating income206,500 204,936 1,564 
Other income (expense):
Equity in earnings of equity method investments12,432 6,647 5,785 
Interest expense, including amortization(53,818)(59,424)5,606 
Interest income29,925 10,621 19,304 
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 other6,179 8,691 (2,512)
19,395 (25,546)44,941 
Income before income taxes225,895 179,390 46,505 
State income tax expense(32)(167)135 
Net income225,863 179,223 46,640 
Allocation of net income attributable to noncontrolling interests(10,917)(8,740)(2,177)
Net income attributable to the partners$214,946 $170,483 $44,463 
Limited partners’ earnings per unit—basic and diluted$2.03 $1.61 $0.42 
Weighted average limited partners’ units outstanding105,440 105,440 — 
EBITDA (1)
$332,671 $319,031 $13,640 
Adjusted EBITDA (1)
$339,203 $345,978 $(6,775)
Distributable cash flow (2)
$269,805 $283,057 $(13,252)
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines108,767 115,827 (7,060)
Affiliates—intermediate pipelines125,225 137,053 (11,828)
Affiliates—crude pipelines279,514 277,025 2,489 
513,506 529,905 (16,399)
Third parties—refined product pipelines49,356 45,685 3,671 
Third parties—crude pipelines129,084 110,691 18,393 
691,946 686,281 5,665 
Terminals and loading racks:
Affiliates391,698 393,300 (1,602)
Third parties51,184 48,909 2,275 
442,882 442,209 673 
Affiliates—refinery processing units69,628 61,416 8,212 
Total for pipelines, terminals and refinery processing unit assets (bpd)1,204,456 1,189,906 14,550 
- 56 -


(1)Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to include the combined resultspartners plus or minus (i) interest expense, (ii) interest income, (iii) state income tax expense and (iv) depreciation and amortization. Adjusted EBITDA is calculated as EBITDA plus (i) loss on early extinguishment of debt, (ii) goodwill impairment, (iii) our share of Osage environmental remediation costs, net of insurance recoveries, included in equity in earnings of equity method investments, (iv) acquisition integration and regulatory costs, (v) tariffs and fees not included in revenues due to impacts from lease accounting for certain tariffs and fees minus (vi) gain on sales-type leases, (vii) gain on significant asset sales, (viii) HEP's pro-rata share of gain on business interruption settlement and (ix) pipeline lease payments not included in operating costs and expenses. Portions of our Predecessor. See Notes 1minimum guaranteed tariffs for assets subject to sales-type lease accounting are recorded as interest income with the remaining amounts recorded as a reduction in net investment in leases. Similarly, certain pipeline lease payments were previously recorded as operating costs and 2expenses, 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 the Consolidated Financial Statementspartners or operating income, as indications of HEPour 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 discussioninternal analysis and as a basis for compliance with financial covenants.

(2)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 exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the basisoperating performance of this presentation.our assets and the cash our business is generating.



 Years Ended December 31,
 202220212020
 (In thousands)
Net income attributable to the partners$216,783 $214,946 $170,483 
Add (subtract):
Interest expense82,560 53,818 59,424 
Interest income(91,406)(29,925)(10,621)
State income tax expense111 32 167 
Depreciation and amortization99,092 93,800 99,578 
EBITDA307,140 332,671 319,031 
Loss on early extinguishment of debt— — 25,915 
Gain on sales-type lease— (24,677)(33,834)
Gain on significant asset sales— (5,263)— 
Goodwill impairment— 11,034 35,653 
HEP's pro-rata share of gain on business interruption insurance settlement— — (6,079)
Share of Osage environmental remediation costs, net of insurance recoveries17,594 — — 
Acquisition integration and regulatory costs2,431 — — 
Tariffs and fees not included in revenues94,592 31,863 11,717 
Lease payments not included in operating costs(6,425)(6,425)(6,425)
Adjusted EBITDA$415,332 $339,203 $345,978 


- 57 -

  Years Ended December 31, Change from
  2017 2016 2016
  (In thousands, except per unit data)
Revenues      
Pipelines:      
Affiliates—refined product pipelines $80,030
 $83,102
 $(3,072)
Affiliates—intermediate pipelines 28,732
 26,996
 1,736
Affiliates—crude pipelines 65,960
 70,341
 (4,381)
  174,722
 180,439
 (5,717)
Third parties—refined product pipelines 52,379
 52,195
 184
Third parties—crude pipelines 7,939
 —
 7,939
  235,040
 232,634
 2,406
Terminals, tanks and loading racks:      
Affiliates 125,510
 119,633
 5,877
Third parties 16,908
 16,732
 176
  142,418
 136,365
 6,053
       
Affiliates—refinery processing units 76,904
 33,044
 43,860
       
Total revenues 454,362
 402,043
 52,319
Operating costs and expenses      
Operations (exclusive of depreciation and amortization) 137,605
 123,986
 13,619
Depreciation and amortization 79,278
 70,428
 8,850
General and administrative 14,323
 12,532
 1,791
  231,206
 206,946
 24,260
Operating income 223,156
 195,097
 28,059
Other income (expense):      
Equity in earnings of equity method investments 12,510
 14,213
 (1,703)
Interest expense, including amortization (58,448) (52,552) (5,896)
Interest income 491
 440
 51
Loss on early extinguishment of debt (12,225) —
 (12,225)
Remeasurement gain on preexisting equity interests 36,254
 —
 36,254
Gain on sale of assets and other 422
 677
 (255)
  (20,996) (37,222) 16,226
Income before income taxes 202,160
 157,875
 44,285
State income tax expense (249) (285) 36
Net income 201,911
 157,590
 44,321
Allocation of net loss attributable to Predecessor —
 10,657
 (10,657)
Allocation of net income attributable to noncontrolling interests (6,871) (10,006) 3,135
Net income attributable to the partners 195,040
 158,241
 36,799
General partner interest in net income attributable to the partners (1)
 (35,047) (57,173) 22,126
Limited partners’ interest in net income $159,993
 $101,068
 $58,925
Limited partners’ earnings per unit—basic and diluted (1)
 $2.28
 $1.69
 $0.59
Weighted average limited partners’ units outstanding 70,291
 59,872
 10,419
EBITDA (2)
 $344,749
 $277,545
 $67,204
Distributable cash flow (3)
 $242,955
 $218,810
 $24,145
       
Volumes (bpd)      
Pipelines:      
Affiliates—refined product pipelines 133,822
 128,140
 5,682
Affiliates—intermediate pipelines 141,601
 137,381
 4,220
Affiliates—crude pipelines 281,093
 277,241
 3,852
  556,516
 542,762
 13,754
Third parties—refined product pipelines 78,013
 75,909
 2,104
Third parties—crude pipelines 21,834
 —
 21,834
  656,363
 618,671
 37,692
Terminals and loading racks:     
Affiliates 428,001
 413,487
 14,514
Third parties 68,687
 72,342
 (3,655)
  496,688
 485,829
 10,859
       
Affiliates—refinery processing units 63,572
 51,778
 11,794
       
Total for pipelines and terminal and refinery processing unit assets (bpd) 1,216,623
 1,156,278
 60,345


 Years Ended December 31,
 202220212020
 (In thousands)
Net income attributable to the partners$216,783 $214,946 $170,483 
Add (subtract):
Depreciation and amortization99,092 93,800 99,578 
Amortization of discount and deferred debt charges3,929 3,757 3,319 
Loss on early extinguishment of debt— — 25,915 
Customer billings greater (less) than net income recognized1,167 3,355 (743)
Maintenance capital expenditures (3)
(19,982)(15,293)(8,643)
Increase (decrease) in environmental liability5,375 (661)(1,020)
Share of remaining Osage insurance coverage estimated to be received9,500 — — 
Decrease in reimbursable deferred revenue(13,828)(13,494)(12,175)
Gain on sales-type lease— (24,677)(33,834)
Gain on significant asset sales— (5,263)— 
Goodwill impairment— 11,034 35,653 
Other5,453 2,301 4,524 
Distributable cash flow$307,489 $269,805 $283,057 



(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.

  Years Ended December 31, Change from
  2016 2015 2015
  (In thousands, except per unit data)
Revenues      
Pipelines:      
Affiliates—refined product pipelines $83,102
 $81,294
 $1,808
Affiliates—intermediate pipelines 26,996
 28,943
 (1,947)
Affiliates—crude pipelines 70,341
 67,088
 3,253
  180,439
 177,325
 3,114
Third parties—refined product pipelines 52,195
 51,022
 1,173
  232,634
 228,347
 4,287
Terminals, tanks and loading racks:      
Affiliates 119,633
 111,933
 7,700
Third parties 16,732
 15,632
 1,100
  136,365
 127,565
 8,800
       
Affiliates—refinery processing units 33,044
 2,963
 30,081
       
Total revenues 402,043
 358,875
 43,168
Operating costs and expenses      
Operations (exclusive of depreciation and amortization) 123,986
 105,556
 18,430
Depreciation and amortization 70,428
 63,306
 7,122
General and administrative 12,532
 12,556
 (24)
  206,946
 181,418
 25,528
Operating income 195,097
 177,457
 17,640
Other income (expense):      
Equity in earnings of equity method investments 14,213
 4,803
 9,410
Interest expense, including amortization (52,552) (37,418) (15,134)
Interest income 440
 526
 (86)
Gain on sale of assets and other 677
 486
 191
  (37,222) (31,603) (5,619)
Income before income taxes 157,875
 145,854
 12,021
State income tax expense (285) (228) (57)
Net income 157,590
 145,626
 11,964
Allocation of net loss attributable to Predecessor 10,657
 2,702
 7,955
Allocation of net income attributable to noncontrolling interests (10,006) (11,120) 1,114
Net income attributable to the partners 158,241
 137,208
 21,033
General partner interest in net income attributable to the partners (1)
 (57,173) (42,337) (14,836)
Limited partners’ interest in net income $101,068
 $94,871
 $6,197
Limited partners’ earnings per unit—basic and diluted (1)
 $1.69
 $1.60
 $0.09
Weighted average limited partners’ units outstanding 59,872
 58,657
 1,215
EBITDA (2)
 $277,545
 $237,180
 $40,365
Distributable cash flow (3)
 $218,810
 $197,046
 $21,764
       
Volumes (bpd)      
Pipelines:      
Affiliates—refined product pipelines 128,140
 124,061
 4,079
Affiliates—intermediate pipelines 137,381
 142,475
 (5,094)
Affiliates—crude pipelines 277,241
 291,491
 (14,250)
  542,762
 558,027
 (15,265)
Third parties—refined product pipelines 75,909
 73,555
 2,354
  618,671
 631,582
 (12,911)
Terminals and loading racks:     
Affiliates 413,487
 391,292
 22,195
Third parties 72,342
 78,403
 (6,061)
  485,829
 469,695
 16,134
       
Affiliates—refinery processing units 51,778
 6,774
 45,004
       
Total for pipelines and terminal and refinery processing unit assets (bpd) 1,156,278
 1,108,051
 48,227
December 31,
20222021
(In thousands)
Balance Sheet Data
Cash and cash equivalents$10,917 $14,381 
Working capital$17,293 $17,461 
Total assets$2,747,502 $2,165,867 
Long-term debt$1,556,334 $1,333,049 
Partners' equity$857,126 $443,017 





(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 included incentive distributions that were 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. As a result of the IDR restructuring transaction, no IDR or general partner distributions were made after October 31, 2017. See "Business and Properties - Overview."

(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 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 Holly Energy 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. See our calculation of EBITDA under Item 6, “Selected Financial Data.”

(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 exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. See our calculation of distributable cash flow under Item 6, “Selected Financial Data.”



Results of Operations — Year Ended December 31, 20172022 Compared with Year Ended December 31, 20162021


Summary
Net income attributable to the partners for the year ended December 31, 2017,2022, was $195.0$216.8 million, a $36.8$1.8 million increase compared to the year ended December 31, 2016.2021. Results for the year ended December 31, 2022, reflect the impact to our equity in earnings of equity method investments of HEP's 50% share of incurred and estimated environmental remediation and recovery expenses, net of insurance proceeds received to date, associated with a release of crude oil on the Osage Pipe Line Company, LLC ("Osage") pipeline of $17.6 million. In addition, results for the year ended December 31, 2021, reflect special items that collectively increased net income attributable to HEP by a total of $18.9 million. These items included a gain on sales type leases of $24.7 million, a gain on significant asset sales of $5.3 million and a goodwill impairment charge of $11.0 million related to our Cheyenne reporting unit. Excluding these items, net income attributable to the partners for the year ended December 31, 2022 was $234.4 million ($1.92 per basic and diluted limited partner unit) compared to $196.0 million ($1.86 per basic and diluted limited partner unit) for the year ended December 31, 2021. The increase in earnings is primarilywas mainly due to (a)net income from Sinclair Transportation, which was acquired on March 14, 2022, higher revenues on our UNEV pipeline and higher net income from our Cushing Connect Joint Venture as the Woods Cross processing units acquiredCushing Connect pipeline went into service in the fourth quarter of 2016, (b) the gain recognized on the acquisition of SLC Pipeline and Frontier Aspen for the remeasurement of preexisting equity interests,September 2021; partially offset by (c) 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 and (d) higher interest expense of $5.9 million.and higher operating costs and expenses.


Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Revenues for the year ended December 31, 2017, include the recognition of $9.7 million of prior shortfalls billed to shippers in 2017 and 2016. As of December 31, 2017, deferred revenue on our consolidated balance sheet related to shortfalls billed was $4.0 million.
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Revenues
Revenues for the year ended December 31, 2017,2022, were $454.4$547.5 million, a $52.3an increase of $53.0 million increase compared to the same period of 2016.year ended December 31, 2021. The increase is primarily duewas mainly attributable to the $43.5 million of revenue recorded for the Woods Cross processing unitsrevenues on our recently acquired Sinclair Transportation assets, increased revenues from our UNEV assets, higher volumes on our crude pipelines in the fourth quarter of 2016New Mexico, Texas, Wyoming and Utah as well as rate increases that went into effect on July 1, 2022, partially offset by lower revenues fromon our Cheyenne assets as a result of the SLC and Frontier Aspen pipelines acquired inconversion of the fourth quarterCheyenne Refinery to renewable diesel production. The year ended December 31, 2021, included the recognition of 2017.the $10 million termination fee related to the termination of HF Sinclair's minimum volume commitment on our Cheyenne assets.
Revenues from our refined product pipelines were $132.4$113.2 million, a decreasean increase of $2.9$5.8 million, on shipments averaging 211.8181.3 mbpd compared to 204.0158.1 mbpd for the year ended December 31, 2016.2021. The decrease involume and revenue 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 decrease of $2.3 million in previously deferred revenue realized. The increase in volumes is primarilyincreases were mainly due to higher volumes on relatively short pipelines with lower tariff rates.our recently acquired Sinclair Transportation assets and higher volumes on our UNEV pipeline. We recognized a significant portion of the Sinclair Transportation refined product pipeline tariffs as interest income under sales-type lease accounting.
Revenues from our intermediate pipelines were $28.7$32.2 million, an increase of $1.7$2.1 million on shipments averaging 141.6compared to the year ended December 31, 2021. Shipments averaged 129.3 mbpd compared to 137.4125.2 mbpd for the year ended December 31, 2016.2021. The increase in revenue isvolumes was mainly due to higher volumes from


throughputs on our intermediate pipelines servicing HFC'sHF Sinclair's Tulsa and Navajo refinery after its turnaroundrefineries and the recently acquired Sinclair Transportation intermediate pipelines, and the increase in revenues was mainly due to the first quarter of 2017 as well as an increase of $1.5 million in previously deferred revenue realized.recently acquired Sinclair Transportation intermediate pipelines.
Revenues from our crude pipelines were $73.9$140.0 million, an increase of $3.6$14.4 million on shipments averaging 302.9compared to the year ended December 31, 2021. Shipments averaged 601.3 mbpd compared to 277.2408.6 mbpd for the year ended December 31, 2016. Revenues2021. The increase in volumes was mainly attributable to our Cushing Connect Pipeline, which went into service in September 2021, volumes on our recently acquired Sinclair Transportation crude pipelines and higher volumes increasedon our crude pipeline systems in New Mexico, Texas, Wyoming and Utah. The increase in revenues was mainly due to revenues from the fourth quarterour recently acquired Sinclair Transportation crude pipelines and higher volumes on our crude pipelines in New Mexico, Texas, Wyoming and Utah. Revenues did not increase in proportion to volumes due to our recognition of 2017 acquisitionmost of the remaining interests in SLCCushing Connect Pipeline tariffs and Frontier Aspen offset by lower throughput due to HFC's Navajo refinery turnaround ina significant portion of the first quarter of 2017.Sinclair Transportation crude pipeline tariffs as interest income under sales-type lease accounting.
Revenues from terminal, tankage and loading rack fees were $142.4$167.8 million, an increase of $6.1$25.5 million compared to the year ended December 31, 2016.2021. Refined products and crude oil terminalled in ourthe facilities increased to an average of 496.7averaged 598.2 mbpd compared to 485.8442.9 mbpd for the year ended December 31, 2016. The volume and revenue increases are2021. Volumes increased mainly due to volumes on our recently acquired Sinclair Transportation assets and higher throughputs at HF Sinclair's Tulsa refinery. Revenues increased mainly due to revenues on our recently acquired Sinclair Transportation assets, higher butane blending revenues and higher revenues on our Tulsa crude tanks acquired onassets. In addition, the last dayyear ended December 31, 2021 included the recognition of the first quarter of 2016, higher throughput on the UNEV terminals, and higher reimbursable revenue$10 million termination fee related to tank inspections and repairs, offset by the transfertermination of HF Sinclair's minimum volume commitment on our Cheyenne assets as a result of the El Paso terminalconversion of the Cheyenne Refinery to HollyFrontier in the first quarter of 2016.renewable diesel production.
Revenues from refinery processing units were $76.9$94.2 million, an increase of $43.9 million on throughputs averaging 63.6 mbpd compared to 51.8 mbpd for 2016. The increase in revenues and volumes is primarily due to the Woods Cross refinery processing units acquired in the fourth quarter of 2016.
Operations Expense
Operations (exclusive of depreciation and amortization) expense for the year ended December 31, 2017, increased by $13.6$5.1 million compared to the year ended December 31, 2016. The increase is primarily due2021. Throughputs averaged 70.2 mbpd compared to operating expenses69.6 mbpd for the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2017,2021. The increase in volumes was mainly due to increased throughput for our Woods Cross processing units. Revenues increased mainly due to higher recovery of natural gas costs as well as higher throughputs.
Operations Expense
Operations (exclusive of depreciation and amortization) expense for the year ended December 31, 2022, increased by $8.9$40.1 million compared to the year ended December 31, 2016.2021. The increase iswas mainly due to depreciation from the Woods Cross refinery processing unitsto operating costs and expenses associated with our recently acquired in the fourth quarter of 2016.Sinclair Transportation assets and higher employee costs, utility costs, natural gas costs, and maintenance costs, partially offset by lower general services costs.


GeneralDepreciation and AdministrativeAmortization
GeneralDepreciation and administrative costsamortization for the year ended December 31, 2017,2022, increased by $1.8$5.3 million compared to the year ended December 31, 2016,2021. The increase was mainly due to higher legal and consulting costsdepreciation on our recently acquired Sinclair Transportation assets partially offset by decreased employee compensation.the acceleration of depreciation on certain of our Cheyenne tanks in 2021 as well as retirement of assets due to sales-type lease accounting.


General and Administrative
General and administrative costs for the year ended December 31, 2022, increased by $4.4 million compared to the year ended December 31, 2021 mainly due to integration costs associated with our acquisition of Sinclair Transportation as well as higher fees charged by HF Sinclair under the Omnibus Agreement for the provision of general and administrative services in the year ended December 31, 2022.
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Equity in Earnings of Equity Method Investments
See the summary chart below for a description of our equity in earnings of equity method investments:
Years Ended December 31,
Equity Method Investment20222021
(In thousands)
Osage Pipe Line Company, LLC$(18,708)$3,889 
Cheyenne Pipeline LLC6,474 5,008 
Cushing Connect Terminal Holdings LLC3,325 3,535 
Pioneer Investments Corp.$9,708 $— 
Saddle Butte Pipeline III, LLC$(1,059)$— 
Total$(260)$12,432 
 Years Ended December 31,
Equity Method Investment2017 2016
 (in thousands)
SLC Pipeline LLC$2,267
 $4,508
Frontier Aspen LLC4,089
 4,130
Osage Pipe Line Company, LLC2,447
 3,250
Cheyenne Pipeline LLC3,707
 2,325
Total$12,510
 $14,213


SLC Pipeline and Frontier Aspen equityEquity in earnings of Osage decreased for the year ended December 31, 20172022, mainly due to HEP's 50% share of incurred and estimated environmental remediation and recovery expenses, net of insurance proceeds received to date, associated with a release of crude oil that occurred in the third quarter of 2022. Additional insurance recoveries will be recorded as they are received. If our insurance policy pays out in full, our share of the remaining insurance coverage is expected to be $9.5 million. The pipeline resumed operations in the third quarter of 2022 and remediation efforts are underway. The decrease in Osage was partially offset by the addition of equity in earnings from Pioneer Investments Corp., reflect the ten months before we purchased their remaining interests on October 31, 2017. SLC Pipeline and Frontier Aspen operations for the two monthswhich was acquired as part of November and December 2017, are included in HEP's consolidated results.our Sinclair Transportation acquisition.


Interest Expense
Interest expense for the year ended December 31, 2017,2022, totaled $58.4$82.6 million, an increase of $5.9$28.7 million compared to the year ended December 31, 2016.2021. The increase is primarilywas mainly due to theour April 2022 issuance of new 6% Senior Notes$400 million in July 2016.aggregate principal amount of 6.375% senior unsecured notes maturing in April 2027, the proceeds of which were used to partially repay outstanding borrowings under our senior secured revolving credit facility following the funding of the cash portion of the Sinclair Transportation acquisition. In addition, market interest rates increased on our senior secured revolving credit facility. Our aggregate effectiveweighted-average interest rate was 4.4%rates were 5.0% and 4.7%3.7% for the years ended December 31, 20172022 and 2016,2021, respectively.


Interest Income
Interest income for the year ended December 31, 2022, totaled $91.4 million, an increase of $61.5 million compared to the year ended December 31, 2021. The increases were mainly due to higher sales-type lease interest income from our recently acquired Sinclair Transportation pipelines and terminals and our Cushing Connect Pipeline, which was placed into service at the end of the third quarter of 2021.

State Income Tax
We recorded state income tax expense of $249,000$111,000 and $285,000$32,000 for the years ended December 31, 20172022 and 2016,2021, respectively. All state income tax expense is solely attributable to the Texas margin tax.






ResultsResults of Operations—Year Ended December 31, 20162021 Compared with Year Ended December 31, 20152020


Summary
Net income attributable to the partners for the year ended December 31, 2016,2021, was $158.2$214.9 million, a $21.0$44.5 million increase compared to the year ended December 31, 2015. The increase in earnings is primarily due to the newly constructed and acquired Woods Cross refinery processing units and recent acquisitions including interests in the Osage and Cheyenne pipelines, the Tulsa crude tanks acquired in the first quarter of 2016, and the El Dorado refinery process units dropped down in the fourth quarter of 2015 as well as increased earnings from our 75% interest in the UNEV products pipeline, offset by higher interest expense associated with our private placement of $400 million in aggregate principal amount of 6% senior unsecured notes due in 2024, which we issued in July and the proceeds of which were used to partially fund our Woods Cross processing units acquisition.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Revenues2020. Results for the year ended December 31, 2016,2021 reflect special items that collectively increased net income attributable to HEP by a total of $18.9 million. These items include a gain on sales type leases of $24.7 million, a gain on significant asset sales of $5.3 million and a goodwill impairment charge of $11.0 million related to our Cheyenne reporting unit. In addition, net income attributable to HEP for the recognition of $10.0 million of prior shortfalls billed to shippers in 2016 and 2015. As ofyear ended December 31, 2016, deferred revenue on our consolidated balance sheet2020 included a goodwill impairment charge of $35.7 million related to shortfalls billed was $5.6 million. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excessour Cheyenne reporting unit, a charge of guaranteed levels, if and$25.9 million related to the extentearly redemption of our previously outstanding $500 million aggregate principal amount of 6% Senior Notes due in 2024, a gain on sales-type leases of $33.8 million 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 HFC's Woods Cross refinery. Excluding these items, net income attributable to the pipeline system will havepartners for the necessary capacity for shipmentsyear ended December 31, 2021 was $196.0 million ($1.86 per basic and diluted limited partner unit) compared to $192.1 million ($1.82 per basic and diluted limited partner unit) in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.2020.


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Revenues
Revenues for the year ended December 31, 2016,2021, were $402.0$494.5 million, a $43.2$3.4 million increasedecrease compared to the same period of 2015.2020. The decrease was mainly attributable to lower on-going revenues from our Cheyenne assets as a result of the conversion of the Cheyenne Refinery to renewable diesel production, lower volumes on our product pipelines servicing HF Sinclair's Navajo refinery and Delek's Big Spring refinery, and recording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue increase was primarilyin the year ended December 31, 2020, partially offset by higher revenues from our crude pipeline systems in Wyoming and Utah and our Woods Cross and El Dorado refinery processing units mainly due to the Woods Cross processing units acquired in the fourth quarterhigher recovery of 2016, the El Dorado processing units acquired in the fourth quarter of 2015, higher UNEV pipeline revenues, and revenues from the Tulsa crude tanks acquired in the first quarter of 2016.natural gas costs.

Revenues from our refined product pipelines were $135.3$107.4 million, an increasea decrease of $3.0$9.5 million, primarily due to increased revenue from the UNEV pipeline of $4.0 million offset by PPI driven tariff rates decreases. Shipments averaged 204.0on shipments averaging 158.1 mbpd compared to 197.6161.5 mbpd for the year ended December 31, 2015, largely2020. The volume and revenue decreases were mainly due to higherlower volumes on our UNEV pipeline.pipelines servicing HFC's Navajo refinery and Delek's Big Spring refinery.

Revenues from our intermediate pipelines were $27.0$30.1 million, a decreasean increase of $1.9$0.1 million, on shipments averaging 137.4125.2 mbpd compared to 142.5137.1 mbpd for the year ended December 31, 2015.2020. The decrease in revenue isvolumes was mainly due to lower volumes fromthroughputs on our intermediate pipelines servicing HFC'sHF Sinclair's Tulsa and Navajo refinery and a $0.7 million decrease in previously deferredrefineries while revenue realized.remained relatively constant mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $70.3$125.6 million, an increase of $3.3$6.7 million, on shipments averaging 277.2408.6 mbpd compared to 291.5387.7 mbpd for the year ended December 31, 2015. Revenues2020. The increases were mainly attributable to increased largelyvolumes on our crude pipeline systems in Wyoming and Utah partially offset by lower volumes on our pipeline systems servicing HF Sinclair's Navajo refinery. Volumes also increased due to an increase in deferred revenue recognized and to a surchargethe addition of volumes on our Beeson expansion. Volumes were lower due to lower throughputCushing Connect Pipeline in Oklahoma which went into service at HFC's Navajo refinery.the end of the third quarter of 2021.

Revenues from terminal, tankage and loading rack fees were $136.4$142.3 million, an increasea decrease of $8.8$9.4 million compared to the year ended December 31, 2015. This increase is due principally to increased revenues from the El Dorado tanks and the newly acquired Tulsa crude tanks.2020. Refined products and crude oil terminalled in ourthe facilities increased to an average of 485.8averaged 442.9 mbpd compared to 469.7442.2 mbpd for the year ended December 31, 2015, largely2020. Revenues decreased mainly due to lower on-going revenues on our Cheyenne assets as a result of the inclusionconversion of volumes from our Tulsa crude tanks acquiredthe Cheyenne Refinery to renewable diesel production and recording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue in the first quarter of 2016 and our El Dorado crude tanks acquired late in the first quarter of 2015, offset by the transfer of the El Paso terminal to HFC in the first quarter of 2016.year ended December 31, 2020

Revenues from refinery processing units were $33.0$89.1 million, an increase of $30.1$8.8 million on throughputs averaging 51.869.6 mbpd compared to 6.861.4 mbpd for 2015. Thisthe year ended December 31, 2020. The increase in revenue is primarilyvolumes was mainly due to theincreased throughput for both our Woods Cross refinery processing units acquired in the fourth quarter of 2016 and an increase in revenue from the El Dorado refinery units acquired late in 2015.processing units. Revenues increased mainly due to higher recovery of natural gas costs as well as higher throughputs.

Operations Expense
Operations (exclusive(exclusive of depreciation and amortization) expense for the year ended December 31, 2016,2021, increased by $18.4$22.8 million compared to the year ended December 31, 2015. 2020. The increase iswas mainly due to operating expenses from the newly constructedan increase in employee costs, maintenance costs, pipeline rental costs and acquired Woods Cross processing units and El Dorado refinery processing units.natural gas costs.


Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2016, increased2021, decreased by $7.1$5.8 million compared to the year ended December 31, 2015.2020. The increase is principallydecrease was mainly due to higher depreciation from our newly acquired Woods Cross refinery processing units.the retirements in Cheyenne operations and sale of El Paso 6-inch pipeline assets.


General and Administrative
General and administrative costs for the year ended December 31, 2016, was in line with2021, increased by $2.6 million compared to the year ended December 31, 2015.2020 primarily due to costs related to the HEP Transaction.

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Equity in Earnings of Equity Method Investments
See the summary chart below for a description of our equity in earnings of equity method investments:
Years Ended December 31,
Equity Method Investment20212020
(In thousands)
Osage Pipe Line Company, LLC3,889 2,416 
Cheyenne Pipeline LLC5,008 2,689 
Cushing Connect Terminal Holdings LLC3,535 1,542 
Total12,432 6,647 
 Years Ended December 31,
Equity Method Investment2016 2015
 (in thousands)
SLC Pipeline LLC$4,508
 $3,306
Frontier Aspen LLC4,130
 1,497
Osage Pipe Line Company, LLC3,250
 —
Cheyenne Pipeline LLC2,325
 —
Total$14,213
 $4,803


SLC PipelineEquity in earnings of Osage Pipe Line Company, LLC increased for the year ended December 31, 2016,2021, mainly due to higher throughput volumes. Equity in earnings of Cheyenne Pipeline LLC increased compared tofor the year ended December 31, 2015,2021, mainly due to higher pipeline throughput volumes. Frontier Aspenthe recognition in revenue of prior contractual minimum commitment billings. Equity in earnings for year ended December 31, 2016, include a full year of operations compared toCushing Connect Terminal Holdings LLC increased for the year ended December 31, 2015,2021 as we acquired our 50% interest on August 31, 2015.the terminal started operations in the second quarter of 2020.


Interest Expense
Interest expense for the year ended December 31, 2016,2021, totaled $52.6$53.8 million, an increasea decrease of $15.1$5.6 million compared to the year ended December 31, 2015.2020. The increase is primarilydecrease was mainly due to the issuance of new 6% Senior Notes in July 2016.lower outstanding balances under our senior secured revolving credit facility. Our aggregate effectiveweighted-average interest rate was 4.7%rates were 3.7% and 4.0%3.8% for the years ended December 31, 20162021 and 2015,2020, respectively.


Interest Income
Interest income for the year ended December 31, 2021, totaled $29.9 million, an increase of $19.3 million compared to the year ended December 31, 2020. The increase was due to recording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue in 2020 as underlying agreements were classified as sales-type leases when the agreements were modified or renewed. See Note 5 of our consolidated financial statements for further discussion of lease accounting.

State Income Tax
We recorded state income tax expense of $285,000$32,000 and $228,000$167,000 for the years ended December 31, 20162021 and 2015,2020, respectively. All state income tax expense is solely attributable to the Texas margin tax.




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 in, decreasing the size of the facility from $1.4 billion to $1.2 billion and extending the maturity date to July 2022.27, 2025. In August 2022, the Credit Agreement was amended to, among other things, provide an alternative reference rate for LIBOR. 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 year ended December 31, 2017,2022, we received advances totaling $969.0$510.0 million and repaid $510.0$682.0 million, resulting in a net increasedecrease of $459.0$172.0 million under the Credit Agreement and an outstanding balance of $1,012.0$668.0 million at December 31, 2017.2022. As of December 31, 2017,2022, we had no letters of credit outstanding under the Credit Agreement, and the available capacity under the Credit Agreement was $388$532.0 million.
If any particular lenderOn April 8, 2022, we closed a private placement of $400 million in aggregate principal amount of 6.375% senior unsecured notes due in 2027 (the “6.375% Senior Notes”). The 6.375% Senior Notes were issued at par for net proceeds of approximately $393 million, after deducting the initial purchasers’ discounts and commissions and estimated offering expenses. The total net proceeds from the offering of the 6.375% Senior Notes were used to partially repay outstanding borrowings under the Credit Agreement, could not honor its commitment, we believe the unused capacity that would beincreasing our available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, we review publicly available information on the lenders in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We do not expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.liquidity.

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On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partnership interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under the Credit Agreement. After this common unit issuance, HFC owns a 57% limited partner interest in us.


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. No units were issued under the program during the year ended December 31, 2022. As of December 31, 2017,2022, HEP hashad issued 2,241,9072,413,153 units under this program, providing $77.1$82.3 million in gross proceeds. We intend to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures.

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


partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions.

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

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


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, and funds available under the Credit Agreement, as well as our access to additional bank financing, and public or private capital markets will provide sufficient resources to meet our working capital liquidity, capital expenditure and quarterly distribution needs for the foreseeable future. Future securities issuances, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.


We remain committed to our capital allocation strategy focused on funding all capital expenditures and distributions within operating cash flow, with the goal of achieving our leverage target of 3.0 - 3.5x and distributable cash flow coverage of 1.3x or greater. We expect to reach our leverage target in mid-2023, and once that target is achieved, we plan to evaluate incremental cash return to unitholders.

In each of February, May, August and November 2017,2022, we paid regular quarterly cash distributions of $0.6075, $0.6200, $0.6325 and $0.6450,$0.3500 on all units for an aggregate amount of $170.0 million during the year ended December 31, 2022. In February 2023, we paid a regular quarterly cash distribution of $0.3500 on all units in an aggregate amount of $234.6 million, including $49.7 million of incentive distribution payments to our general partner. In February 2018, we paid a regular cash distribution of $0.6500 on all units in an aggregate amount of $63.5 million after deducting HEP Logistics' waiver of $2.5 million of limited partner cash distributions.$44.3 million.


Cash and cash equivalents increaseddecreased by $4.1$3.5 million during the year ended December 31, 2017.2022. The cash flows provided by operating activities of $331.0 million and financing activities of $238.5$35.5 million and $51.9 million, respectively, were moreless than the cash flows used for investing activities of $286.3$370.0 million. Working capital increaseddecreased by $26.7$0.2 million to a surplus of $18.9$17.3 million at December 31, 20172022 from a deficiencysurplus of $7.8$17.5 million at December 31, 2016.2021.


Cash Flows—Operating Activities
Year Ended December 31, 20172022 Compared with Year Ended December 31, 20162021
Cash flows provided by operating activities increased by $37.0 million from $294.1 million for the year ended December 31, 2021, to $331.0 million for the year ended December 31, 2022. This increase was mainly due to higher cash receipts from customers, partially offset by higher payments for turnaround expenses at our Woods Cross refinery processing units, higher payments for operating expenses and higher payments for interest expenses in the year ended December 31, 2022, as compared to the prior year.

Year Ended December 31, 2021 Compared with Year Ended December 31, 2020
Cash flows provided by operating activities decreased by $5.1$21.5 million from $243.5$315.6 million for the year ended December 31, 2016,2020, to $238.5$294.1 million for the year ended December 31, 2017. 2021. This decrease iswas mainly due principally to higher payments for interest and operating expenses partially offset by increasedhigher cash receipts from customers and lower payments for interest expenses in the year ended December 31, 2017,2021, as compared to the prior year.


Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements, these shippers have the right to recapture these amounts if future volumes exceed minimum levels. We billed $9.7 million during the year ended December 31, 2016, related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2017. Another $4.0 million is included as deferred revenue on our balance sheet at December 31, 2017, related to shortfalls billed during the year ended December 31, 2017.Cash Flows—Investing Activities

Year Ended December 31, 20162022 Compared with Year Ended December 31, 20152021
Cash flows from operatingused for investing activities increased by $12.1$291.6 million from $231.4$78.5 million for the year ended December 31, 2015,2021, to $243.5$370.0 million for the year ended December 31, 2016. This increase is due principally to higher cash receipts for services performed and higher distributions received from equity investments partially offset by higher payments for interest and operating expenses in2022. During the year ended December 31, 2016, as compared2022, we made payments of $329.0 million related to the prior year.

Our major shippers are obligatedacquisition of Sinclair Transportation. During the years ended December 31, 2022 and 2021, we invested $39.0 million and $90.0 million, respectively, in additions to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements, these shippers have the right to recapture these amounts if future volumes exceed minimum levels. We billed $10.0properties and equipment. In addition, we received proceeds from sales of assets of $0.3 million and $7.4 million during the yearyears ended December 31, 20152022 and 2016, related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2016. Another $5.6 million is included as deferred revenue on our balance sheet at December 31, 2016, related to shortfalls billed during the year ended December 31, 20162021, respectively.




Cash Flows—Investing Activities
Year Ended December 31, 20172021 Compared with Year Ended December 31, 20162020
Cash flows used for investing activities increased by $143.2$18.7 million from $143.0$59.8 million for the year ended December 31, 2016,2020, to $286.3$78.5 million for the year ended December 31, 2017.2021. During the years ended December 31, 20172021 and 2016,2020, we invested $44.8$90.0 million and $59.7$59.3 million, respectively, in additions to properties and equipment, respectively. We acquired the remaining 75% interest in SLC Pipeline and 50% interest in Frontier Aspen for $245.4 million in October 2017. We acquired a 50% interest in Cheyenne Pipeline LLC for $42.6 million in June 2016 as well as $44.1 million for the Woods Cross refinery processing units and Tulsa tanks.

Year Ended December 31, 2016 Compared with Year Ended December 31, 2015
Cash flows used for investing activities decreased by $103.7 million from $246.7 million for the year ended December 31, 2015, to $143.0 million for the year ended December 31, 2016. During the years ended December 31, 2016 and 2015,equipment. In addition, we invested $59.7 million and $39.4 million in additions to properties and equipment, respectively. We acquired a 50% interest in Cheyenne Pipeline LLC for $42.6 million in June 2016, a 50% interest in Frontier Pipeline for $55.0 million in August 2015, and the El Dorado crude tank assets for $27.5 million in March 2015. We have retrospectively adjusted our historical financial results for all periods to include the Woods Cross refinery processing units and Tulsa tanks for the periods we were under common control of HFC. Therefore, cash flows from investing activities reflect outflows of $44.1 million for the Woods Cross refinery processing units and Tulsa tanks in 2016 and $98.6 million in 2015. The year ended December 31, 2015 also reflects outflows of $27.6 million related to our acquisition of the El Dorado refinery processing units. We received $3.0 million of distributions in excess of earnings of our equity method investments. We received $0.4 million in proceeds from the salesales of assets of $7.4 million during the year ended December 31, 2016.2021.

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Cash Flows—Financing Activities
Year Ended December 31, 20172022 Compared with Year Ended December 31, 20162021
Cash flows from financing activities increased by $258.7 million from $223.2 million used for the year ended December 31, 2021, to $35.5 million provided by financing activities were $51.9for the year ended December 31, 2022. During the year ended December 31, 2022, we received $510.0 million and repaid $682.0 million in advances under the Credit Agreement. Additionally, we paid $170.0 million in regular quarterly cash distributions to HEP unitholders and $9.7 million to our noncontrolling interests. We also received net proceeds of $393.5 million from the issuance of our 6.375% Senior Notes. During the year ended December 31, 2021, we received $480.5 million and repaid $554.0 million in advances under the Credit Agreement. Additionally, we paid $149.4 million in regular quarterly cash distributions to HEP unitholders and $10.7 million to our noncontrolling interests.

Year Ended December 31, 2021 Compared with Year Ended December 31, 2020
Cash flows used for financing activities decreased by $23.9 million from $247.2 million for the year ended December 31, 2017, compared2020, to cash flows used by financing activities of $111.9$223.2 million for the year ended December 31, 2016, an increase of $163.8 million.2021. During the year ended December 31, 2017,2021, we received $969.0$480.5 million and repaid $510.0$554.0 million in advances under the Credit Agreement. We also received net proceeds of $101.8 million from the issuance of our 6% Senior Notes and $52.1 million from issuance of common units. Additionally, we paid $309.8 million for the redemption of our 6.5% Senior notes, $234.6$149.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners and $6.5$10.7 million to our noncontrolling interest. interests. We also paid $9.4received $23.2 million in deferred financing charges to amendcontributions from our noncontrolling interests during the Credit Agreement.year ended December 31, 2021. During the year ended December 31, 2016,2020, we received $554.0$258.5 million and repaid $713.0$310.5 million in advances under the Credit Agreement. We also received net proceeds of $394.0 million from the issuance of our 6% Senior Notes and $125.9 million from the issuance of common units. We alsoAdditionally, we paid $192.0$174.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners, paid $5.8$9.8 million to our noncontrolling interest and paid $3.5 million for the purchase of common units for recipients of our incentive grants. In addition, we received $51.3 million for the Woods Cross Operating and Tulsa tank acquisitions, and recorded distributions to HFC for the acquisitions of $317.5 million.

Year Ended December 31, 2016 Compared with Year Ended December 31, 2015
Cash flows used for financing activities were $111.9 million for the year ended December 31, 2016, compared to cash flows provided by financing activities of $27.4 million for the year ended December 31, 2015, a decrease of $139.3 million. During the year ended December 31, 2016, we received $554.0 million and repaid $713.0 million in advances under the Credit Agreement.interests. We also received net proceeds of $394.0$491.3 million from the issuance of our 6%5% Senior Notes and $125.9 million from issuance of common units. Additionally, we paid $192.0 million in regular quarterly cash distributions to our general and limited partners, $5.8$522.5 million to retire our noncontrolling interest and $3.5 million for the purchase of common units for recipients of our incentive grants. We have retrospectively adjusted our historical financial results for all periods to include the Woods Cross refinery processing units and Tulsa tanks for the periods we were under common control of HFC. Therefore, we recorded contributions from HFC for the Woods Cross Operating and Tulsa tank acquisitions of $51.3 million and recorded distributions to HFC for the acquisitions of $317.5 million. We paid $1.2 million to HFC related to the Osage acquisition. We also paid $4.0 million in deferred financing charges to amend the Credit Agreement. During the year ended December 31, 2015, we received $973.9 million and repaid $832.9 million in advances under the Credit Agreement. We also paid $169.1 million in regular quarterly cash distributions to our general and limited partners, paid $4.6 million to our noncontrolling interest and paid $3.6 million for the purchase of common units for recipients of our incentive grants. In addition, we received $27.6 million for the El Dorado Operating acquisition, $0.9 million for Tulsa tank expenditures from HFC, $99.9 million for the Woods Cross Operating acquisition, and recorded distributions to HFC for the El Dorado Operating acquisition of $62.0 million.6% Senior Notes.


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.but exclude acquisitions. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.


Each year the board of directors of HLS, our ultimate general partner, approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2018 Our current 2023 capital budgetforecast is comprised of $8approximately $25 million to $35 million for maintenance capital expenditures and approximately $40$5 to $10 million for expansion capital expenditures. We expect the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks,expenditures and enhanced blending capabilities at our racks.joint venture investments. In addition to our capitalcapital budget, we may spend funds periodically to perform capital upgrades or additions to our assets where a customer reimburses us for such costs. The upgrades or additions would generally benefit the customer over the remaining life of the related service agreements.

We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects, will be funded with cash generated by operations,operations. We expect that, to the sale ofextent necessary, we can raise additional limited partner common units, the issuance offunds from time to time through equity or debt securities and advances under our Credit Agreement, or a combination thereof. With volatility and uncertainty at timesfinancings in the creditpublic 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 additionalprivate capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.markets.


Under the terms of the transaction to acquire HFC’s 75% interest in UNEV, we issued to a subsidiary of HFC (now HF Sinclair) a Class B unit comprising a noncontrolling equity interest in a wholly-ownedwholly owned subsidiary subject to redemption to the extent that HFC (now HF Sinclair) is entitled to a 50% interest in our share75% of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30$40 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. In August 2022, the Credit Agreement was amended to, among other things, provide an alternative reference rate for LIBOR. 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. As of December 31, 2017,2022, we had outstanding borrowings of $1,012$668.0 million under the Credit Agreement, no letters of credit outstanding, and the available capacity was $388$532.0 million.


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 at any time without penalty, except for tranche breakage costs. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies. We were in compliance with all covenants under the Credit Agreement as of December 31, 2017.2022.


IndebtednessPrior to the Investment Grade Date (as defined in the Credit Agreement), indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced byAlternate Base Rate (as defined in the administrative agentCredit Agreement) plus an applicable margin (ranging from 0.50%0.75% to 1.50%1.75%) or (b) Adjusted Term SOFR (net of our unrestricted cash and Liquid Investments (as defined in the Credit Agreement) at a rate equalsuch time in an amount not to LIBORexceed $50.0 million) plus an applicable margin (ranging from 1.50%1.75% to 2.50%2.75%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). The weighted-average interest rates on our Credit Agreement borrowings in effect atfor the years ending December 31, 20172022 and 2016,2021, were 3.734% 4.02% and 2.978%2.30%, respectively. WePrior to the Investment Grade Date, we incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30%0.25% to 0.50% based upon the ratio of our funded debt (net of our unrestricted cash and Liquid Investments at such time in an amount not to exceed $50.0 million) to EBITDA for the four most recently completed fiscal quarters.


quarters.


Senior Notes
On January 4, 2017,April 8, 2022, we redeemed the $300closed a private placement of $400 million in aggregate principal amount of the 6.5%6.375% Senior Notes. The 6.375% Senior Notes maturing 2020were issued at a redemption costpar for net proceeds of $309.8approximately $393 million, at which time we recognized a $12.2 million early extinguishment loss. We fundedafter deducting the redemption withinitial purchasers’ discounts and commissions and offering expenses. The total net proceeds from the offering of the 6.375% Senior Notes were used to partially repay outstanding borrowings under the Credit Agreement, increasing our Credit Agreement.available liquidity.


We haveAs of December 31, 2022, we had $500 million in aggregate principal amount of 6%5% Senior Notes due in 2024. We used2028 (the “5% Senior Notes,” and together with the net proceeds from our offerings of the 6%6.375% Senior Notes, to repay indebtedness under our Credit Agreement.the “Senior Notes”).


The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of December 31, 2017.2022. At any time when the 6% 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% Senior Notes.


Indebtedness under the 6% 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).


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Long-term Debt
The carrying amounts of our long-term debt are as follows:
December 31,
2022		December 31,
2021
(In thousands)
Credit Agreement
Amount outstanding$668,000 $840,000 
5% Senior Notes
Principal500,000 500,000 
Unamortized debt issuance costs(5,953)(6,951)
494,047 493,049 
6.375% Senior Notes
    Principal400,000 — 
Unamortized debt issuance costs(5,713)— 
394,287 — 
Total long-term debt$1,556,334 $1,333,049 
  December 31,
2017		 December 31,
2016
  (In thousands)
Credit Agreement $1,012,000
 $553,000
     
6% Senior Notes    
Principal 500,000
 400,000
Unamortized debt issuance costs (4,692) (6,607)
  495,308
 393,393
6.5% Senior Notes    
Principal —
 300,000
Unamortized discount and debt issuance costs —
 (2,481)
  —
 297,519
     
Total long-term debt $1,507,308
 $1,243,912

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


Long-term Contractual Obligations
The following table presents our long-term contractual obligations as of December 31, 2017.2022.


   Payments Due by Period  Payments Due by Period
 Total 
Less than
1 Year
 1-3 Years 3-5 Years 
Over 5
Years
 TotalLess than
1 Year		1-3 Years3-5 YearsOver 5
Years
 (In thousands) (In thousands)
Long-term debt – principal $1,512,000
 $—
 $—
 $1,012,000
 $500,000
Long-term debt – principal$1,568,000 $— $668,000 $400,000 $500,000 
Long-term debt - interest 370,300
 67,800
 135,600
 119,400
 47,500
Long-term debt - interest346,578 93,700 168,920 81,750 2,083 
Site service fees 243,772
 5,133
 10,266
 10,266
 218,107
Site service fees238,505 5,681 11,362 11,362 210,100 
Pipeline operating lease 61,038
 6,425
 12,850
 12,850
 28,913
Pipeline finance leasePipeline finance lease32,621 7,249 14,498 10,874 — 
Right-of-way agreements and other 20,035
 4,007
 5,792
 4,064
 6,172
Right-of-way agreements and other19,794 5,783 7,528 1,902 4,581 
Total $2,207,145
 $83,365
 $164,508
 $1,158,580
 $800,692
Total$2,205,498 $112,413 $870,308 $505,888 $716,764 
Long-term debt consists of outstanding principal under the Credit Agreement and the Senior Notes. Interest on the credit agreementCredit Agreement is calculated using the rate in effect at December 31, 2017.


2022.
Site service fees consist of site service agreements with HFC,HF Sinclair, expiring in 2058 through 2066, for the provision of certain facility services and utility costs that relate to our assets located at HFC’sHF Sinclair’s refinery facilities. We are presenting obligations for the full term of these agreements; however, the agreements can be terminated with 180 day notice if we cease to operate the applicable assets.
The pipeline operatingfinance lease amounts above reflect the exercise of the second 10-year extension, expiring in 2027, on our lease agreement for the refined products pipeline between White Lakes Junction and Kuntz Station in New Mexico.
Most of our right-of-way agreements are renewable on an annual basis, and the right-of-way agreements payments above include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2017.2022. For the foreseeable future, we intend to continue renewing these agreements and expect to incur right-of-way expenses in addition to the payments listed.
Other contractual obligations include capital lease obligations related to vehicles leases, office space leases, and other.


Impact of Inflation
Inflation in the United States has beenAfter being relatively moderate in recent years, PPI in the United States increased significantly in 2022 and did not have a material impact on our results of operations for the years ended December 31, 2017, 20162021 (13.5% and 20158.9%, respectively). PPI has increased an average of 0.4% annually over the past five calendar years, including an increase of 3.2% and a decrease of 1.0% in 2017 and 2016, respectively.


The substantial majority of our revenues are generated under long-term contracts that provide for increases or decreases in our rates and minimum revenue guarantees annually for increases or decreases in the PPI. These annual rate adjustments generally occur on July 1st each year based on the PPI or FERC index increase or decrease during the prior year. Certain of these
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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. The substantial majority of our rates and minimum revenue guarantees used the 2021 PPI increase of 8.9% in the July 1, 2022 rate adjustment calculations.

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. However, for the year ended December 31, 2022, the fees we charged our shippers increased at a rate greater than our inflationary cost increase.


Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.
Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Some environmental laws impose liability without regard to fault or the legality of the original act on certain classes of persons that contributed to the releases of hazardous substances or petroleum hydrocarbon substances into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since thewastes.
There are environmental remediation of such releases would be covered under environmental indemnification agreements.
projects in progress, including assessment and monitoring activities, that relate to certain assets acquired from HF Sinclair. Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFCHF Sinclair, HF Sinclair 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 HFCHF Sinclair and occurring or existing prior to the date of such transfers.
We have an environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations.
There are environmental remediation projects in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities retained by HFC. As of December 31, 2017,2022, we have an accrual of $6.5$19.5 million that relates to environmental clean-up projects for which we have assumed liability, including accrued environmental liabilities assumed in the Sinclair Transportation acquisition that have preliminarily been fair valued at $14.7 million as of the acquisition date, or for which the indemnity provided for by HFCHF Sinclair has expired orexpired.
On July 8, 2022, the Osage pipeline, which carries crude oil from Cushing, Oklahoma to El Dorado, Kansas, suffered a release of crude oil. Our equity in earnings (loss) of equity method investments was reduced in the year ended December 31, 2022 by $17.6 million for our 50% share of incurred and estimated environmental remediation and recovery expenses associated with the release, net of our share of insurance proceeds received to date of $3.0 million. We expect Osage will expire.receive additional insurance recoveries, which will be recorded as they are received. If our insurance policy pays out in full, our share of the remaining insurance coverage is expected to be $9.5 million. The remaining projects, including assessmentpipeline resumed operations in the third quarter of 2022 and monitoring activities,remediation efforts are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.underway.



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CRITICAL ACCOUNTING POLICIES AND ESTIMATES


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. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.


Revenue Recognition
Revenues are generally recognized as products are shipped through our pipelines and terminals, or feedstocks are processed bythrough our refinery processing units. Additional pipelineunits or other services are rendered. The majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) the possibility is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. Prior to the adoption of the new lease standard (see below), we bifurcated the consideration received between lease and service revenue. The new lease standard allows the election of a practical expedient whereby a lessor does not have to separate non-lease (service) components from lease components under certain conditions. The majority of our contracts meet these conditions, and we have made this election for those contracts. Under this practical expedient, we treat the combined components as a single performance obligation in accordance with Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09, if the non-lease (service) component is the dominant component. If the lease component is the dominant component, we treat the combined components as a lease in accordance with ASC 842, which largely codified ASU 2016-02.
Several of our contracts include incentive or reduced tariffs once a certain quarterly volume is met. Revenue from the variable element of these transactions is recognized based on the actual volumes shipped as it relates specifically to rendering the services during the applicable quarter.
The majority of our long-term transportation revenues result from an operating lease by Alon USA, L.P., which was acquired by Delek and is referred to herein as Delek,contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of an interestshipments in the capacity of one of our pipelines.

Billings to customers forevent a customer ships below their obligations under their quarterly minimum revenue commitmentscontractual requirements. If there are recorded as deferred revenue liabilities if the customer has the right to receiveno future services for these billings. The revenue is recognized at the earlier of:

the customer receiving the future services provided by these billings,
the period in which the customer is contractually allowed to receive the services expires, or
our determination thatperformance obligations, we will not be required to provide services within the allowed period.recognize these deficiency payments in revenue.

We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enableIn certain of these throughput agreements, a customer to exceedmay later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum volume levels to such a degree as to utilize the shortfall credit 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.


Leases
We adopted ASC 842 effective January 1, 2019, and elected to adopt using the modified retrospective transition method and practical expedients, both of 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 use our estimated incremental borrowing rate (“IBR”) to determine the present value of lease payments as most of our leases do not contain an implicit rate. Our IBR represents the interest rate which we would pay to borrow, on a collateralized basis, an amount equal to the 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.
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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.

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

Our annual goodwill impairment testing for 2022 and 2021 was performed on a qualitative basis during the present valuethird quarters of the expected future net cash flows2022 and market multiple analyses to determine the estimated fair values of the reporting units. The impairment test requires the use of projections, estimates and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss. In 2017, we2021. We assessed qualitative factors such as macroeconomic conditions, industry considerations, cost factors and reporting unit financial performance and determined it iswas not more likely than not that the fair value of our reporting units arewas less than the respective carrying value. Therefore, in accordance with generally accepted accounting principles,GAAP, further testing was not required.


During the first quarter of 2021, changes in our agreements with HFC related to our Cheyenne assets resulted in an increase in the carrying amount 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.

Our annual goodwill testing for 2020 was performed on a quantitative basis during the third quarter of 2020. The estimated fair value of our reporting units derived using a combination of both income and market approaches as described above. Our annual testing of goodwill in 2020 identified an impairment charge of $35.7 million, which was recorded in the third quarter of 2020, related to our Cheyenne reporting unit.

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


There have been no impairmentsValuation of Business Combinations
We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date. Any excess or surplus of the purchase consideration when compared to the fair value of the net tangible assets acquired, if any, is recorded as goodwill or our long-livedgain from a bargain purchase. The fair value of assets through December 31, 2017.and liabilities as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project future cash flows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity-specific differences. We use all available information to make these fair value determinations and engage third-party consultants for valuation assistance. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ materially from the projected results used to determine fair value.


Contingencies
It is common in our industry to beWe are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these types of matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these types of contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.

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Accounting Pronouncement Adopted During the Periods Presented

Share-Based Compensation
In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for tax-withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in operating activities. The impact of this change for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $0.8 million and $0.7 million, respectively. Finally, consistent with our existing policy, we have elected 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. In preparing for adoption, we have evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we have implemented policies to comply with this new standard, which we do not anticipate will have a material impact on our financial condition, results of 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 matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.


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


At December 31, 2017,2022, we had an outstanding principal balance of $500$900.0 million on our 6% Senior Notes. A change in interest rates generally would affect the fair value of the 6% Senior Notes, but not our earnings or cash flows. At December 31, 2017,2022, the fair value of our 6% Senior Notes was $525$852.7 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6% Senior Notes at December 31, 2017,2022, would result in a change of approximately $15$24.2 million in the fair value of the underlying 6% Senior Notes.


For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2017,2022, borrowings outstanding under the Credit Agreement were $1,012$668.0 million. A hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.


At our election, certain borrowings under our variable rate Credit Agreement bear interest at a variable rate based on the secured overnight financing rate (“SOFR”) as administered by the Federal Reserve Bank of New York.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured


against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.


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




Item 7A.Quantitative and Qualitative Disclosures about Market Risk
Item 7A.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. We utilize derivative instruments to hedge our interest rate exposure, as discussed under “Risk Management.”
Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have direct market risks associated with commodity prices.

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Item 8.Financial Statements and Supplementary Data
Item 8.Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE PARTNERSHIP’S INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Energy Partners, L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the Partnership’s internal control over financial reporting as of December 31, 2017,2022, using the criteria for effective control over financial reporting established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this assessment, management concluded that, as of December 31, 2017,2022, the Partnership maintained effective internal control over financial reporting.
Management excluded SLC Pipeline Management’s assessment of, and Frontier Aspen, which were acquiredconclusion on, October 31, 2017, from our assessmentthe effectiveness of internal control over financial reporting as of December 31, 2017. See Note 2did not include the internal controls of the 2017HEP Acquired Sinclair Businesses, that were acquired on March 14, 2022, as we are in the process of integrating operations of the HEP Acquired Sinclair Businesses, including internal controls over financial reporting. The HEP Acquired Sinclair Businesses accounted for approximately 26% of the Partnership's consolidated financial statements for additional information. SLC Pipelinetotal assets and Frontier Aspen represent approximately 17%5% of consolidated total assetsrevenues of the Partnership as of December 31, 2017, and 2% of total revenues for the year ended December 31, 2017.2022.
The Partnership’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2017.2022. That report appears on page 60.72.




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Unitholders of Holly Energy Partners, L.P. and the Board of Directors of Holly Logistic Services, L.L.C.


Opinion on Internal Control overOver Financial Reporting
We have audited Holly Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2017,2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Holly Energy Partners, L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2022, based on the COSO criteria.

As indicated in the accompanying Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of SLC Pipeline LLC and Frontier Aspen LLC acquired on October 31, 2017,the HEP Acquired Sinclair Businesses, which areis included in the 20172022 consolidated financial statements of the Partnership and constituted 17%approximately 26% of consolidated total assets as of December 31, 20172022 and 2%5% of consolidated total revenues for the year then ended. Our audit of internal control over financial reporting of the PartnershipCompany also did not include an evaluation of the internal control over financial reporting of SLC Pipeline LLC and Frontier Aspen LLC.

the HEP Acquired Sinclair Businesses.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 20172022 and 2016,2021, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2017,2022, and the related notes of the Partnership, and our report dated February 21, 201828, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.




Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



/s/ ERNSTErnst & YOUNGYoung LLP
Dallas, Texas
February 21, 201828, 2023

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Index to Consolidated Financial Statements
 
Page
Reference
Page
Reference
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
6574
6676
6777
68
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 20162022, 2021 and 20152020
6978
7079
7180



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To Unitholders of Holly Energy Partners, L.P. and the Board of Directors of Holly Logistic Services, L.L.C.



Opinion on the Financial Statements


We have audited the accompanying consolidated balance sheets of Holly Energy Partners, L.P. (the Partnership) as of December 31, 20172022 and 2016,2021, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2017,2022, and the related notes (collectively referred to as the "financial statements"“consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2022, in conformity with U.S. generally accepted accounting principles.


We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2017,2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 21, 201828, 2023 expressed an unqualified opinion thereon.

Basis for Opinion


These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.



Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.


Sales-Type Lease Accounting
Description of the Matter
As disclosed in Note 5 of the financial statements, the Partnership entered into new agreements and amended other agreements which met the criteria of sales-type leases. Under sales-type lease accounting, the lessor recognizes a net investment in the lease and derecognizes the underlying asset with any difference recorded as a gain or loss at the lease commencement date. During the year ended December 31, 2022, the Partnership recorded total net investment in leases of $234.7 million.

Auditing management’s accounting for sales-type leases was complex and highly judgmental due to the estimation uncertainty in determining the fair value of the underlying leased assets at the commencement date of the leases. The fair value of the underlying leased assets is factored into the Partnership’s determination of the net investment in the leases. The fair value estimates for these assets were sensitive to significant assumptions including replacement cost as adjusted for physical deterioration. These assumptions have a significant effect on the fair value estimates of the assets acquired.
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How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership's evaluation of the lease classification and related accounting for the sales-type leases. For example, we tested controls over management's review of the significant inputs and assumptions used in estimating the fair value of the underlying leased assets.

To test the Partnership’s accounting for the sales-type leases, our audit procedures included, among others, evaluating the Partnership’s selection of the valuation methodology, evaluating the significant assumptions used by the Partnership, and evaluating the completeness and accuracy of the underlying data supporting the significant assumptions and estimates. We involved valuation specialists to assist with our evaluation of the methodologies used by the Partnership and significant assumptions included in the fair value estimates. Specifically, our valuation specialists assisted by comparing those assumptions to current industry and market data and developing an expected range of values based on significant inputs and assumptions to assess reasonableness of the Partnership’s estimates.
Valuation of Personal Property Assets in the Sinclair Transportation Company Acquisition
Description of the Matter
During 2022, the Partnership completed its acquisition of Sinclair Transportation Company for an aggregate $678.0 million in cash and common limited partner units, as disclosed in Note 2 to the consolidated financial statements. The transaction was accounted for as a business combination. Of the total assets acquired and liabilities assumed, the Partnership acquired $340.7 million of properties, plant, and equipment, which was made up of real and personal property.

Auditing management's accounting for the acquisition of Sinclair Transportation Company was complex due to the significant estimation uncertainty in determining the fair value of certain properties, plant and equipment. In particular, the fair value estimates for Sinclair Transportation Company personal property were sensitive to significant assumptions including replacement cost as adjusted for physical deterioration. These assumptions have a significant effect on the fair value estimates of the assets acquired.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership's controls over the valuation of the personal property assets related to the acquisition. For example, we tested controls over management’s review of the valuation models and the underlying assumptions used to develop estimated values of these assets.

To test the estimated fair value of the personal property, our audit procedures included, among others, evaluating the Partnership’s selection of the valuation methodology, evaluating the significant assumptions used by the Partnership, and evaluating the completeness and accuracy of the underlying data supporting the significant assumptions and estimates. We involved valuation specialists to assist with our evaluation of the methodologies used by the Partnership and significant assumptions included in the fair value estimates. Specifically, our valuation specialists assisted by comparing those assumptions to current industry and market data and developing an expected range of values based on significant inputs and assumptions to assess reasonableness of the Partnership’s estimates.

/s/ ERNSTErnst & YOUNGYoung LLP
We have served as the Partnership's auditor since 2003.
Dallas, Texas
February 21, 201828, 2023



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HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(inIn thousands, except unit data)

 December 31, 2017 December 31, 2016December 31, 2022December 31, 2021
ASSETS    ASSETS
Current assets:    Current assets:
Cash and cash equivalents $7,776
 $3,657
Cash and cash equivalents (Cushing Connect VIEs: $2,147 and $8,881, respectively)
Cash and cash equivalents (Cushing Connect VIEs: $2,147 and $8,881, respectively)
$10,917 $14,381 
Accounts receivable:    Accounts receivable:
Trade 12,803
 7,846
Trade16,344 12,745 
Affiliates 51,501
 42,562
Affiliates63,459 56,154 
 64,304
 50,408
79,803 68,899 
Prepaid and other current assets 2,311
 2,888
Prepaid and other current assets12,397 11,033 
Total current assets 74,391
 56,953
Total current assets103,117 94,313 
    
Properties and equipment, net 1,569,471
 1,328,395
Properties and equipment, net1,388,888 1,329,028 
Operating lease right-of-use assetsOperating lease right-of-use assets2,317 2,275 
Net investment in leases (Cushing Connect VIEs: $101,871 and $100,042, respectively)
Net investment in leases (Cushing Connect VIEs: $101,871 and $100,042, respectively)
539,705 309,303 
Intangible assets, net 129,463
 66,856
Intangible assets, net59,300 73,307 
Goodwill 266,716
 256,498
Goodwill342,762 223,650 
Equity method investments 85,279
 165,609
Equity method investments (Cushing Connect VIEs: $34,746 and $37,505, respectively)
Equity method investments (Cushing Connect VIEs: $34,746 and $37,505, respectively)
270,604 116,378 
Deferred turnaround costsDeferred turnaround costs24,154 2,632 
Other assets 28,794
 9,926
Other assets16,655 14,981 
Total assets $2,154,114
 $1,884,237
Total assets$2,747,502 $2,165,867 
    
LIABILITIES AND EQUITY    LIABILITIES AND EQUITY
Current liabilities:    Current liabilities:
Accounts payable:    Accounts payable:
Trade $14,547
 $10,518
Trade (Cushing Connect VIEs: $431 and $8,285, respectively)
Trade (Cushing Connect VIEs: $431 and $8,285, respectively)
$26,753 $28,577 
Affiliates 7,725
 16,424
Affiliates15,756 11,703 
 22,272
 26,942
42,509 40,280 
    
Accrued interest 13,256
 18,069
Accrued interest17,992 11,258 
Deferred revenue 9,598
 11,102
Deferred revenue12,087 14,585 
Accrued property taxes 4,652
 5,397
Accrued property taxes5,449 4,542 
Current operating lease liabilitiesCurrent operating lease liabilities968 620 
Current finance lease liabilitiesCurrent finance lease liabilities4,389 3,786 
Other current liabilities 5,707
 3,225
Other current liabilities2,430 1,781 
Total current liabilities 55,485
 64,735
Total current liabilities85,824 76,852 
    
Long-term debt 1,507,308
 1,243,912
Long-term debt1,556,334 1,333,049 
Noncurrent operating lease liabilitiesNoncurrent operating lease liabilities1,720 2,030 
Noncurrent finance lease liabilitiesNoncurrent finance lease liabilities62,513 64,649 
Other long-term liabilities 15,843
 16,445
Other long-term liabilities29,111 12,527 
Deferred revenue 47,272
 47,035
Deferred revenue24,613 29,662 
    
Class B unit 43,141
 40,319
Class B unit60,507 56,549 
    
Equity:    Equity:
Partners’ equity:    Partners’ equity:
Common unitholders (101,568,955 and 62,780,503 units issued and outstanding
at December 31, 2017 and 2016, respectively)
 393,959
 510,975
General partner interest —
 (132,832)
Accumulated other comprehensive income —
 91
Common unitholders (126,440,201 and 105,440,201 units issued and outstanding
at December 31, 2022 and 2021, respectively)
Common unitholders (126,440,201 and 105,440,201 units issued and outstanding
at December 31, 2022 and 2021, respectively)
857,126 443,017 
Total partners’ equity 393,959
 378,234
Total partners’ equity857,126 443,017 
Noncontrolling interest 91,106
 93,557
Noncontrolling interestsNoncontrolling interests69,754 147,532 
Total equity 485,065
 471,791
Total equity926,880 590,549 
Total liabilities and equity $2,154,114
 $1,884,237
Total liabilities and equity$2,747,502 $2,165,867 
See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit data) 


 Years Ended December 31,
 202220212020
Revenues:
Affiliates$438,280 $390,849 $399,809 
Third parties109,200 103,646 98,039 
547,480 494,495 497,848 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)210,623 170,524 147,692 
Depreciation and amortization99,092 93,800 99,578 
General and administrative17,003 12,637 9,989 
       Goodwill impairment— 11,034 35,653 
326,718 287,995 292,912 
Operating income220,762 206,500 204,936 
Other income (expense):
Equity in earnings (losses) of equity method investments(260)12,432 6,647 
Interest expense(82,560)(53,818)(59,424)
Interest income91,406 29,925 10,621 
Gain on sales-type lease— 24,677 33,834 
Loss on early extinguishment of debt— — (25,915)
Gain on sale of assets and other668 6,179 8,691 
9,254 19,395 (25,546)
Income before income taxes230,016 225,895 179,390 
State income tax expense(111)(32)(167)
Net income229,905 225,863 179,223 
Allocation of net income attributable to noncontrolling interests(13,122)(10,917)(8,740)
Net income attributable to the partners216,783 214,946 170,483 
Limited partners’ per unit interest in earnings—basic and diluted$1.77 $2.03 $1.61 
Weighted average limited partners’ units outstanding122,298 105,440 105,440 
  Years Ended December 31,
  2017 2016 2015
Revenues:      
Affiliates $377,136
 $333,116
 $292,221
Third parties 77,226
 68,927
 66,654
  454,362
 402,043
 358,875
Operating costs and expenses:      
Operations (exclusive of depreciation and amortization) 137,605
 123,986
 105,556
Depreciation and amortization 79,278
 70,428
 63,306
General and administrative 14,323
 12,532
 12,556
  231,206
 206,946
 181,418
Operating income 223,156
 195,097
 177,457
       
Other income (expense):      
Equity in earnings of equity method investments 12,510
 14,213
 4,803
Interest expense (58,448) (52,552) (37,418)
Interest income 491
 440
 526
Loss on early extinguishment of debt (12,225) —
 —
Remeasurement gain on preexisting equity interests 36,254
 —
 —
Gain on sale of assets and other 422
 677
 486
  (20,996) (37,222) (31,603)
Income before income taxes 202,160
 157,875
 145,854
State income tax expense (249) (285) (228)
Net income 201,911
 157,590
 145,626
Allocation of net loss attributable to Predecessor —
 10,657
 2,702
Allocation of net income attributable to noncontrolling interests (6,871) (10,006) (11,120)
Net income attributable to the partners 195,040
 158,241
 137,208
General partner interest in net income attributable to the Partnership, including incentive distributions (35,047) (57,173) (42,337)
Limited partners’ interest in net income $159,993
 $101,068
 $94,871
Limited partners’ per unit interest in earnings—basic and diluted $2.28
 $1.69
 $1.60
Weighted average limited partners’ units outstanding 70,291
 59,872
 58,657


Net income and comprehensive income are the same in all periods presented.
See accompanying notes.


HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)


- 77 -
  Years Ended December 31,
  2017 2016 2015
Net income $201,911
 $157,590
 $145,626
       
Other comprehensive income:      
Change in fair value of cash flow hedging instruments 88
 (607) (1,864)
Reclassification adjustment to net income on partial settlement of cash flow hedge (179) 508
 2,100
Other comprehensive income (loss) (91) (99) 236
Comprehensive income before noncontrolling interest 201,820
 157,491
 145,862
Allocation of net loss attributable to Predecessor —
 10,657
 2,702
Allocation of comprehensive income to noncontrolling interests (6,871) (10,006) (11,120)
       
Comprehensive income attributable to the partners $194,949
 $158,142
 $137,444


See accompanying notes.



HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In                         (In thousands)    
 Years Ended December 31, Years Ended December 31,
 2017 2016 2015 202220212020
Cash flows from operating activities      Cash flows from operating activities
Net income $201,911
 $157,590
 $145,626
Net income$229,905 $225,863 $179,223 
Adjustments to reconcile net income to net cash provided by operating activities:      Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 79,278
 70,428
 63,306
Depreciation and amortization99,092 93,800 99,578 
Gain on sale of assets (319) (150) (375)Gain on sale of assets(209)(5,567)(1,015)
Remeasurement gain on preexisting equity interests (36,254) —
 —
Gain on sales-type leaseGain on sales-type lease— (24,677)(33,834)
Goodwill impairmentGoodwill impairment— 11,034 35,653 
Amortization of deferred charges 3,063
 3,247
 1,928
Amortization of deferred charges3,929 3,757 3,319 
Equity-based compensation expense 2,520
 3,519
 4,180
Equity-based compensation expense1,845 2,557 2,193 
Equity in earnings of equity method investments, net of distributions

 1,450
 (2,032) (122)
Equity in losses of equity method investments
Equity in losses of equity method investments
19,769 — 1,084 
Loss on early extinguishment of debt 12,225
 —
 —
Loss on early extinguishment of debt— — 25,915 
(Increase) decrease in operating assets:      (Increase) decrease in operating assets:
Accounts receivable—trade (38) 279
 (1,820)Accounts receivable—trade(594)1,798 4,188 
Accounts receivable—affiliates (8,939) (10,080) 1,419
Accounts receivable—affiliates(7,305)(8,182)1,744 
Prepaid and other current assets 830
 1,598
 (626)Prepaid and other current assets(254)(255)(1,272)
Increase (decrease) in operating liabilities:      Increase (decrease) in operating liabilities:
Accounts payable—trade (1,975) (365) (1,996)Accounts payable—trade847 912 2,208 
Accounts payable—affiliates (8,699) (16) 6,396
Accounts payable—affiliates4,054 (6,417)1,383 
Accrued interest (4,813) 11,317
 137
Accrued interest6,734 366 (2,314)
Deferred revenue (1,267) 7,058
 9,255
Deferred revenue(7,546)(1,144)(4,122)
Accrued property taxes (2,179) 1,633
 1,061
Accrued property taxes(66)550 193 
Other current liabilities 2,091
 (553) (499)Other current liabilities(141)(724)200 
Turnaround expendituresTurnaround expenditures(24,953)(2,500)(132)
Other, net (398) 75
 3,572
Other, net5,942 2,924 1,435 
Net cash provided by operating activities 238,487
 243,548
 231,442
Net cash provided by operating activities331,049 294,095 315,627 
      
Cash flows from investing activities      Cash flows from investing activities
Additions to properties and equipment (44,810) (59,704) (39,393)Additions to properties and equipment(38,964)(89,995)(59,283)
Acquisition of tanks and refinery processing units —
 (44,119) (153,728)
Purchase of interest in Cheyenne Pipeline —
 (42,627) —
Purchase of interest in Frontier Aspen —
 —
 (55,032)
Purchase of controlling interests in SLC Pipeline and Frontier Aspen (245,446) —
 —
Proceeds from sale of assets 849
 427
 1,279
Acquisition of Sinclair TransportationAcquisition of Sinclair Transportation(328,955)— — 
Purchase of interest in Cushing Connect Pipeline & TerminalPurchase of interest in Cushing Connect Pipeline & Terminal— — (2,438)
Investment in Osage Pipe Line Company, LLCInvestment in Osage Pipe Line Company, LLC(13,000)— — 
Proceeds from sales of assetsProceeds from sales of assets279 7,365 1,089 
Distributions in excess of equity in earnings of equity investments 3,134
 2,993
 194
Distributions in excess of equity in earnings of equity investments10,623 4,165 882 
Net cash used for investing activities (286,273) (143,030) (246,680)Net cash used for investing activities(370,017)(78,465)(59,750)
      
Cash flows from financing activities      Cash flows from financing activities
Borrowings under credit agreement 969,000
 554,000
 973,900
Borrowings under credit agreement510,000 480,500 258,500 
Repayments of credit agreement borrowings (510,000) (713,000) (832,900)Repayments of credit agreement borrowings(682,000)(554,000)(310,500)
Redemption of 6.5% Senior Notes (309,750) —
 —
Proceeds from issuance of 6% Senior Notes 101,750
 394,000
 —
Proceeds from issuance of common units 52,110
 125,870
 —
Redemption of senior notesRedemption of senior notes— — (522,500)
Proceeds from issuance of senior notesProceeds from issuance of senior notes400,000 — 500,000 
Contributions from general partner 1,072
 2,577
 —
Contributions from general partner— — 988 
Contribution from noncontrolling interestsContribution from noncontrolling interests— 23,194 23,899 
Distributions to HEP unitholders (234,575) (192,037) (169,063)Distributions to HEP unitholders(169,998)(149,432)(174,443)
Distributions to noncontrolling interest (6,500) (5,750) (4,625)
Distribution to HFC for acquisitions —
 (317,500) (62,000)
Contributions from HFC for acquisitions —
 51,262
 128,476
Contributions to HFC for El Dorado Operating Tanks (103) —
 —
Distributions to HFC for Osage acquisition —
 (1,245) —
Distributions to noncontrolling interestsDistributions to noncontrolling interests(9,676)(10,743)(9,770)
Payments on finance leasesPayments on finance leases(3,743)(3,549)(3,602)
Purchase of units for incentive grants —
 (3,521) (3,555)Purchase of units for incentive grants(1,727)(1,958)(698)
Units withheld for tax withholding obligations (605) (800) (696)Units withheld for tax withholding obligations(636)(590)(334)
Deferred financing costs (9,382) (3,995) (962)Deferred financing costs(6,546)(6,661)(8,714)
Other (1,112) (1,735) (1,154)Other(170)— — 
Net cash provided by (used for) financing activities 51,905
 (111,874) 27,421
Net cash provided by (used for) financing activities35,504 (223,239)(247,174)
      
Cash and cash equivalents      Cash and cash equivalents
Increase (decrease) for the year 4,119
 (11,356) 12,183
Increase (decrease) for the year(3,464)(7,609)8,703 
Beginning of year 3,657
 15,013
 2,830
Beginning of year14,381 21,990 13,287 
End of year $7,776
 $3,657
 $15,013
End of year$10,917 $14,381 $21,990 
Supplemental disclosure of cash flow information:Supplemental disclosure of cash flow information:
Cash paid during the period for interestCash paid during the period for interest$72,316 $49,990 $58,138 
See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)


 Common
Units		Noncontrolling
Interests		Total
Balance December 31, 2019$381,103 $106,655 $487,758 
Capital contribution-Cushing Connect— 23,899 23,899 
Capital contribution -Cheyenne988 — 988 
Distributions to HEP unitholders(174,443)— (174,443)
Distributions to noncontrolling interests— (9,770)(9,770)
Purchase of units for incentive grants(698)— (698)
Amortization of restricted and performance units2,193 — 2,193 
Class B unit accretion(3,458)— (3,458)
Other(334)— (334)
 Net income173,941 5,282 179,223 
Balance December 31, 2020379,292 126,066 505,358 
Capital contribution-Cushing Connect— 23,194 23,194 
Distributions to HEP unitholders(149,432)— (149,432)
Distributions to noncontrolling interests— (10,743)(10,743)
Purchase of units for incentive grants(1,958)— (1,958)
Amortization of restricted and performance units2,557 — 2,557 
Class B unit accretion(3,699)— (3,699)
Other(2,388)1,797 (591)
 Net income218,645 7,218 225,863 
Balance December 31, 2021443,017 147,532 590,549 
Issuance of common units349,020 — 349,020 
Distributions to HEP unitholders(169,998)— (169,998)
Distributions to noncontrolling interests— (9,676)(9,676)
Acquisition of remaining UNEV interests19,735 (78,010)(58,275)
Purchase of units for incentive grants(1,727)— (1,727)
Amortization of restricted and performance units1,845 — 1,845 
Class B unit accretion(3,958)— (3,958)
Other(1,549)744 (805)
 Net income220,741 9,164 229,905 
Balance December 31, 2022857,126 69,754 926,880 
  Holly Energy Partners, L.P. Partners’ Equity (Deficit):    
  
Common
Units
 
General
Partner
Interest
 
Accumulated
Other
Comprehensive
Income/(Loss)
 
Noncontrolling
Interest
 Total
Balance December 31, 2014 $468,813
 $30,941
 $(46) $95,082
 $594,790
Distributions to HEP unitholders (127,152) (41,911) —
 —
 (169,063)
Distributions to noncontrolling interests —
 —
 —
 (4,625) (4,625)
Contribution from HFC for acquisitions —
 128,477
 —
 —
 128,477
Distribution to HFC for acquisitions —
 (62,000) —
 —
 (62,000)
Purchase of units for incentive grants (3,555) —
 —
 —
 (3,555)
Amortization of restricted and performance units 3,484
 —
 —
 —
 3,484
Class B unit accretion (7,005) (143) —
 —
 (7,148)
 Net income 93,434
 48,220
 —
 3,972
 145,626
 Other comprehensive income —
 —
 236
 —
 236
Balance December 31, 2015 $428,019
 $103,584
 $190
 $94,429
 $626,222
Issuance of common units 125,870
 —
 —
 —
 125,870
Capital contribution —
 2,577
 —
 —
 2,577
Distributions to HEP unitholders (138,779) (53,258) —
 —
 (192,037)
Distributions to noncontrolling interests —
 —
 —
 (5,750) (5,750)
Contributions from HFC for acquisitions —
 82,549
 —
 —
 82,549
Distribution to HFC for acquisitions —
 (317,500) —
 —
 (317,500)
Purchase of units for incentive grants (3,521) —
 —
 —
 (3,521)
Amortization of restricted and performance units 2,719
 —
 —
 —
 2,719
Class B unit accretion (6,250) (128) —
 —
 (6,378)
Other —
 (451) —
 —
 (451)
 Net income 102,917
 49,795
 —
 4,878
 157,590
 Other comprehensive income —
 —
 (99) —
 (99)
Balance December 31, 2016 $510,975
 $(132,832) $91
 $93,557
 $471,791
Issuance of common units 52,100
 —
 —
 —
 52,100
Capital contribution —
 1,072
 —
 —
 1,072
Distributions to HEP unitholders (181,439) (53,136) —
 —
 (234,575)
Distributions to noncontrolling interests —
 —
 —
 (6,500) (6,500)
Distribution to HFC for acquisitions —
 (103) —
 —
 (103)
Amortization of restricted and performance units 1,915
 —
 —
 —
 1,915
Class B unit accretion (2,780) (42) —
 —
 (2,822)
Other 367
 —
 —
 —
 367
Net income 162,815
 35,047
 —
 4,049
 201,911
Equity restructuring transaction (149,994) 149,994
 —
 —
 —
Other comprehensive loss —
 —
 (91) —
 (91)
Balance December 31, 2017 $393,959
 $—
 $—
 $91,106
 $485,065
See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 20172022


Note 1:Description of Business and Summary of Significant Accounting Policies

Note 1:Description of Business and Summary of Significant Accounting Policies

Holly Energy Partners, L.P. (“HEP”), together with its consolidated subsidiaries, is a publicly held master limited partnership which is 59% owned (including the non-economic general partner interest) by HollyFrontier Corporation (“HFC”) and its subsidiaries.partnership. We commenced operations on July 13, 2004, upon the completion of our initial public offering. On March 14, 2022 (the “Closing Date”), HollyFrontier Corporation (“HFC”) and HEP announced the establishment of HF Sinclair Corporation, a Delaware corporation (“HF Sinclair”), as the new parent holding company of HFC and HEP and their subsidiaries, and the completion of their respective acquisitions of Sinclair Oil Corporation (now known as Sinclair Oil LLC (“Sinclair Oil”)) and Sinclair Transportation Company LLC (“Sinclair Transportation”) from REH Company (formerly known as The Sinclair Companies, and referred to herein as “REH Company”). On the Closing Date, pursuant to that certain Business Combination Agreement, dated as of August 2, 2021 (as amended on March 14, 2022, the “Business Combination Agreement”), by and among HFC, HF Sinclair, Hippo Merger Sub, Inc., a wholly owned subsidiary of HF Sinclair (“Parent Merger Sub”), REH Company, and Hippo Holding LLC (now known as Sinclair Holding LLC), a wholly owned subsidiary of REH Company (the “Target Company”), HF Sinclair completed its acquisition of the Target Company by effecting (a) a holding company merger in accordance with Section 251(g) of the Delaware General Corporation Law whereby HFC merged with and into Parent Merger Sub, with HFC surviving such merger as a direct wholly owned subsidiary of HF Sinclair (the “HFC Merger”), and (b) immediately following the HFC Merger, a contribution whereby REH Company contributed all of the equity interests of the Target Company to HF Sinclair in exchange for shares of HF Sinclair, resulting in the Target Company becoming a direct wholly owned subsidiary of HF Sinclair (together with the HFC Merger, the “HFC Transactions”).

As of December 31, 2022, HF Sinclair and its subsidiaries owned a 47% limited partner interest and the non-economic general partner interest in HEP.

In connection with the closing of the HFC Transactions, HF Sinclair issued 60,230,036 shares of HF Sinclair common stock to REH Company, representing 27% of the pro forma equity of HF Sinclair with a value of approximately $2,149 million based on HFC’s fully diluted shares of common stock outstanding and closing stock price on March 11, 2022. References herein to HF Sinclair with respect to time periods prior to March 14, 2022 refer to HFC and its consolidated subsidiaries and do not include the Target Company, Sinclair Transportation or their respective consolidated subsidiaries. References herein to HF Sinclair with respect to time periods from and after March 14, 2022 refer to HF Sinclair and its consolidated subsidiaries, which includes the combined business operations of HFC, the Target Company, Sinclair Transportation and their respective consolidated subsidiaries.

Additionally, on the Closing Date, pursuant to that certain Contribution Agreement, dated August 2, 2021 (as amended on March 14, 2022, the “Contribution Agreement”) by and among REH Company, Sinclair Transportation and HEP, HEP acquired all of the outstanding equity interests of Sinclair Transportation from REH Company in exchange for 21 million newly issued common limited partner units of HEP (the “HEP Units”), representing 16.6% of the pro forma outstanding HEP Units with a value of approximately $349 million based on HEP’s fully diluted common limited partner units outstanding and closing unit price on March 11, 2022, and cash consideration equal to $329.0 million, inclusive of final working capital adjustments pursuant to the Contribution Agreement for an aggregate transaction value of $678.0 million (the “HEP Transaction” and together with the HFC Transactions, the “Sinclair Transactions”). Of the 21 million HEP Units, 5.29 million units are currently held in escrow to secure REH Company’s renewable identification numbers (“RINs”) credit obligations to HF Sinclair under Section 6.22 of the Business Combination Agreement. HF Sinclair, and not HEP, would be entitled to the HEP common units held in escrow in the event of REH Company’s breach of its RINs credit obligations under the Business Combination Agreement. The cash consideration was funded through a draw under HEP’s senior secured revolving credit facility. The HEP Transaction was conditioned on the closing of the HFC Transactions, which occurred immediately following the HEP Transaction.

References herein to HEP with respect to time periods prior to March 14, 2022, include HEP and its consolidated subsidiaries and do not include Sinclair Transportation and its consolidated subsidiaries (collectively, the “Acquired Sinclair Businesses”). References herein to HEP with respect to time periods from and after March 14, 2022 include the operations of the Acquired Sinclair Businesses.

In these consolidated financial statements, the words “we,” “our,”“we”, “our”, “ours” and “us” refer to HEP unless the context otherwise indicates.indicates otherwise.

- 80 -

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

We own andand/or operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support HFC’sthe refining and marketing operations of HF Sinclair and other refineries in the Mid-Continent, Southwest and Northwest regions of the United States and Delek US Holdings, Inc.’s (“Delek”) refinery in Big Spring, Texas.States. Additionally, we own a 75% interest in the UNEV Pipeline, LLC (“UNEV”),(a) a 50% interestinterest in Osage Pipe Line Company, LLC (“Osage”), and(b) a 50% interest in Cheyenne Pipeline LLC, (c) a 50% interest in Cushing Connect Pipeline & Terminal LLC, (d) a 25.06% interest in Saddle Butte Pipeline III, LLC and (e) a 49.995% interest in Pioneer Investments Corp. Following the HEP Transaction (see Note 2), we now own the remaining 25% interest in UNEV Pipeline, LLC and as a result, UNEV Pipeline, LLC is our wholly owned subsidiary.

On June 1, 2020, HFC announced plans to permanently cease petroleum refining operations at its Cheyenne Pipeline LLC.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 two five-year renewal option periods for HFC’s (and now HF Sinclair'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 (and now HF Sinclair) will pay a base tariff to HEP for available crude oil storage and HFC (and now HF Sinclair) and HEP will split any profits generated on crude oil contango opportunities and (3) HFC paid 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 HF Sinclair’s Navajo refinery to terminals in El Paso for gross proceeds of $7.0 million and recognized a gain on sale of $5.3 million.

We operate in two reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note 14.16.

Our Pipelines and Terminals segment consists of:
26 main pipeline segments
Crude gathering networks in Texas and New Mexico
10 refined product terminals
1 crude terminal
31,800 track feet of rail storage located at two facilities
7 locations with truck and/or rail racks
Tankage at all six of HFC's refining facility locations

Our Refinery Processing Unit segment consists of five refinery processing units at two of HFC's refining facility locations.


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.


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.control through an ownership interest greater than 50% or through a controlling financial interest with respect to variable interest entities. All significant intercompany transactions and balances have been eliminated.

Most of our acquisitions from HFC occurred while we were a consolidated variable interest entity 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. U.S. generally accepted accounting principles ("GAAP") require transfers of a business between entities under common control to be accounted for as though the transfer occurred as of the beginning of the period of transfer, and Certain prior period financial statements and financial information are retrospectively adjusted to include the historical results and assets of the acquisitions from HFCbalances have been reclassified for all periods presented prior to the effective dates of each acquisition. We refer to the historical results of the acquisitions prior to their respective acquisition dates as those of our "Predecessor." Many of these transactions are cash purchases and do not involve the issuance of equity; however, GAAP requires the retrospective adjustment of financial statements. Therefore, in such transactions, the priorconsistency with current year balance sheet includes as equity the amount of cost incurred by HFC to that date.presentation.



Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.


Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheets approximate fair value due to the short-term maturity of these instruments.


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Accounts Receivable
The majority of the accounts receivable are due from affiliates of HFC, DelekHF Sinclair or independent companies in the petroleum industry. Credit is extended based on evaluation of the customer's financial condition, and in certain circumstances, collateral such as letters of credit or guarantees, may be required. We reserve for doubtful accounts based on our historical loss experience as well as expected credit losses from current economic conditions and management’s expectations of future economic conditions. Credit losses are charged to incomethe allowance for doubtful accounts when accounts arean account is deemed uncollectible and historically have been minimal.


Properties and Equipment
Properties and equipment are stated at cost. Properties and equipment acquired from HFC while under common control of HFC are stated at HFC's historical basis. Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 15 to 25 years for terminal facilities and tankage, 25 to 3230 years for pipelines, 25 years for refinery processing units and 53 to 10 years for corporate and other assets. We depreciate assets acquired under capital leases over the lesser of the lease term or the economic life of the assets. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvements are capitalized.


Intangible Assets
Intangible assets include transportation agreements and acquired customer relationship intangible assets. Intangible assets are stated at acquisition date fair value and are being amortized over their useful lives using the straight-line method.


Goodwill and Long-Lived Assets
Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized. We test goodwill atsubject to amortization and is tested annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting 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, includinga 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. In prior years,unit is impaired, and we usedmeasure goodwill impairment as the present valueexcess of the expected future net cash flows and market multiple analyses to determine the estimated fair valuescarrying amount of the reporting units. Theunit over the related fair value.

Indicators of Goodwill and Long-Lived Asset Impairment
Our annual goodwill impairment test requirestesting for 2022 and 2021 was performed on a qualitative basis during the usethird quarters of projections, estimates2022 and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss. In 2017 and 2016, we2021. We assessed qualitative factors such as macroeconomic conditions, industry considerations, cost factors and reporting unit financial performance and determined it iswas not more likely than not that the fair value of our reporting units arewere less than the respective carrying value. Therefore, in accordance with GAAP, further testing was not required.


During the first quarter of 2021, changes in our agreements with HFC related to our Cheyenne assets resulted in an increase in the carrying amount 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.

Our annual impairment testing for 2020 was performed on a quantitative basis during the third quarter of 2020. The estimated fair value of our reporting units were derived using a combination of both income and market approaches as described above. Our annual testing of goodwill in 2020 identified an impairment charge of $35.7 million, which was recorded in the third quarter of 2020, related to our Cheyenne reporting unit.

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The following is a summary of our goodwill balances:

December 31,
2022		December 31,
2021
 (In thousands)
Goodwill$389,448 $270,336 
Accumulated impairment losses(46,686)(46,686)
$342,762 $223,650 

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

There have been no impairments to goodwill or our long-lived assets through December 31, 2017.


Investment in Equity Method Investments
We account for our interests in noncontrolling joint venture interests using the equity method of accounting, whereby we record our pro-rata share of earnings of these companies, and contributions to and distributions from the joint ventures as adjustments to our investment balances. The difference between the cost of an investment and our proportionate share of the underlying equity in net assets recorded on the investee's books is allocated to the various assets and liabilities of the equity method investment.


The following table summarizes our recorded investments compared to our share of underlying equity for each investee. We are amortizing the differences as adjustments to our pro-rata share of earnings over the useful lives of the underlying assets of these joint ventures. See SLC Pipeline LLC ("SLC Pipeline") and Frontier Aspen LLC ("Frontier Aspen") discussion in Note 2 regarding our purchase of a controlling interest in joint ventures previously accounted for under the equity method.


Balance at December 31, 2022
Underlying EquityRecorded Investment BalanceDifference
(In thousands)
Equity Method Investments
Osage Pipe Line Company, LLC$2,901 $29,773 $(26,872)
Cheyenne Pipeline LLC27,655 40,019 (12,364)
Cushing Connect Terminal Holdings LLC49,915 34,746 15,169 
Pioneer Investments Corp.23,835 133,182 (109,347)
Saddle Butte Pipeline III, LLC67,349 32,884 34,465 
Total$171,655 $270,604 $(98,949)

Balance at December 31, 2021
Underlying EquityRecorded Investment BalanceDifference
(In thousands)
Equity Method Investments
Osage Pipe Line Company, LLC$9,996 $37,782 $(27,786)
Cheyenne Pipeline LLC28,557 41,091 (12,534)
Cushing Connect Terminal Holdings LLC52,203 37,505 14,698 
Total$90,756 $116,378 $(25,622)

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  Balance at December 31, 2017
  Underlying Equity Recorded Investment Balance Difference
  (in thousands)
Equity Method Investments      
Osage Pipe Line Company, LLC $10,631
 $42,071
 $(31,440)
Cheyenne Pipeline LLC 28,706
 43,208
 (14,502)
Total $39,337
 $85,279
 $(45,942)

  Balance at December 31, 2016
  Underlying Equity Recorded Investment Balance Difference
  (in thousands)
Equity Method Investments      
SLC Pipeline LLC $57,273
 $24,417
 $32,856
Frontier Aspen LLC 11,630
 53,160
 (41,530)
Osage Pipe Line Company, LLC 10,730
 43,375
 (32,645)
Cheyenne Pipeline LLC 29,658
 44,657
 (14,999)
Total $109,291
 $165,609
 $(56,318)

Asset Retirement Obligations
We record legal obligations associated with the retirement of certain of our long-lived assets that result from the acquisition, construction, development and/or the normal operation of our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. For our pipeline assets, the right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon cessation of the pipeline service. Additionally, management is unable to predict when, or if, our pipelines and related facilities would become obsolete and require decommissioning. Accordingly, we have recorded no liability or corresponding asset related to an asset retirement obligation for the majority of our pipelines as both the amounts and timing of such potential future costs are indeterminable. For our remaining assets, at December 31, 20172022 and 2016,2021, we have asset retirement obligations of $8.6$10.5 million and $8.0$8.7 million,, respectively, that are recorded under “Other long-term liabilities” in our consolidated balance sheets.


Class B Unit
Under the terms of the transaction to acquire HFC's 75% interest in UNEV, we issued to a subsidiary of HFC (now HF Sinclair) a Class B unit comprising a noncontrolling equity interest in a wholly-ownedwholly owned subsidiary subject to redemption to the extent that HFC (now HF Sinclair) is entitled to a 50% interest in our share75% of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30$40 million beginning July 1, 2016,2015, and ending in June 2032, subject to certain limitations. Such contingent redemption payments are limited to the unredeemed value of the Class B Unit. However, to the extent earnings thresholds are not achieved, no redemption payments are required. No redemption payments have been required to date.

Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional four quarters if HFC's Woods Cross refinery expansion did not attain certain thresholds. HEP Logistics' waiver of its right to incentive distributions of $1.25 million per quarter ended with the distribution paid in the third quarter of 2016.


Pursuant to the terms of the transaction agreements, the Class B unit increases by the amount of each foregone incentive distribution and by a 7% factor compounded annually on the outstanding unredeemed balance through its expiration date. At our option, we

may redeem, in whole or in part, the Class B unit at the current unredeemed value based on the calculation described. The Class B unit had a carrying value of $43.1$60.5 million at December 31, 2017,2022, and $40.3$56.5 million at December 31, 2016.2021.


Revenue Recognition
Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. BillingsThe majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) it is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. Prior to customersthe adoption of the new lease standard (see below), we bifurcated the consideration received between lease and service revenue. The new lease standard allows the election of a practical expedient whereby a lessor does not have to separate non-lease (service) components from lease components under certain conditions. The majority of our contracts meet these conditions, and we have made this election for their obligations under their quarterly minimum revenue commitments are recordedthose contracts. Under this practical expedient, we treat the combined components as deferred revenue liabilitiesa single performance obligation in accordance with Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09, if the customer hasnon-lease (service) component is the right to receive future services fordominant 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 billings. The revenuetransactions is recognized atbased on the earlier of:

the customer receiving the future services provided by these billings,
the period in which the customer is contractually allowedactual volumes shipped as it relates specifically to receiverendering the services expires, orduring the applicable quarter.
The majority of our determination thatlong-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 not be required to provide services within the allowed period.recognize these deficiency payments in revenue.

We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enableIn certain of these throughput agreements, a customer to exceedmay later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum volume levels to such a degree as to utilize the shortfall credit 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 have additional revenues under an operating leaserecognize these deficiency payments in revenue when we do not expect we will be required to a third party of an interestsatisfy these performance obligations in the capacityfuture based on the pattern of onerights projected to be exercised by the customer. During the years ended December 31, 2022, 2021 and 2020, we recognized $21.1 million, $17.5 million and $20.8 million, respectively, of these deficiency payments in revenue, of which $4.2 million, $0.5 million and $0.7 million, respectively,
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related to deficiency payments billed in prior periods. There was no deferred revenue reflected in our pipelines.

Asconsolidated balance sheet related to shortfalls as of December 31, 2017, customers' minimum revenue commitments per the terms of long-term throughput agreements expiring in 2019 through 2036 and the third party operating lease require minimum annualized payments to us in the aggregate of $2.6 billion including $367 million for the year ending December 31, 2018, $341 million for the year ending December 31, 2019, $291 million for the year ending December 31, 2020, $284 million for the year ending December 31, 2021 and $258 million for the year ending December 31, 2022. These agreements provide for changes in the minimum revenue guarantees annually for increases or decreases in the PPI or the FERC index, with certain contracts having provisions that limit the level of the rate increases or decreases.

We have other cost reimbursement provisions in our throughput / throughput/storage agreements providing that customers (including HFC)HF Sinclair) 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.


Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.


Leases
We adopted ASC 842 effective January 1, 2019, and elected to adopt using the modified retrospective transition method and practical expedients, both of 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 use our estimated incremental borrowing rate (“IBR”) to determine the present value of lease payments as most of our leases do not contain an implicit rate. Our IBR represents the interest rate which we would pay to borrow, on a collateralized basis, an amount equal to the 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.

Environmental Costs
Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information.


Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFCHF Sinclair, HF Sinclair, 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 HFCHF Sinclair, occurring or existing prior to the date of such transfers. We have an environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations. Environmental costs recoverable through insurance, indemnification agreements or other sources are included in other assets to the extent such recoveries are considered probable.


Income Tax
We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.
We are organized as a pass-through entity for U.S. federal income tax purposes. As a result, our partners are responsible for U.S. federal income taxes based on their respective share of taxable income.

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Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Net Income per Limited Partners' Unit
We use the two-class method when calculating the net income per unit applicable to limited partners since we had more than one class of participating securities prior to the October 31, 2017 equity restructuring transaction discussed above. Under the two-class method, net income per unit applicable to limited partners is computed by dividing limited partners' interest in net income, after adjusting for the allocation of net income or loss attributable to the Predecessor, the allocation of net income or loss attributable to noncontrolling interests and the general partner's 2% interest and incentive distributions, both of which were applicable prior to the October 31, 2017 equity restructuring transaction discussed above, and other participating securities, by the weighted-average number of common units outstanding during the year and other dilutive securities. Other participating securities and dilutive securities are not significant.


Accounting Pronouncement Adopted During the Periods Presented


Share-Based CompensationCredit Losses Measurement
In MarchJune 2016, an accounting standard updateASU 2016-13, “Measurement of Credit Losses on Financial Instruments,” was issued which simplifiesrequiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeituresreporting date based on historical experience, current conditions and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted thisreasonable and supportable forecasts. This standard was effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for tax-withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in operating activities. The impact of this change for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $0.8 million and $0.7 million, respectively. Finally, consistent with our existing policy, we have elected 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 as2020. Adoption of the date of initial application. In preparing for adoption, we have evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we have implemented policies to comply with this new standard which we dodid not anticipate will have a material impact on our financial condition, results of operations or cash flows.


Business CombinationsAccounting Pronouncements - Not Yet Adopted

In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accountingOctober 2021, Accounting Standards Update 2021-08, “Accounting for identifiable intangible assets in business combinations. This standard has an effective date of January 1, 2018, and we are evaluating its impact.

FinancialContract Assets and Contract Liabilities
In January 2016, an accounting standard update from Contracts with Customers” was issued requiring changesthat an acquiring entity recognize and measure contract assets and contract liabilities acquired in the accounting and disclosures for financial instruments.a business combination in accordance with Accounting Standards Codification (“ASC”) 606 – Revenue from Contracts with Customers. This standard is effective for fiscal years beginning after December 15, 2022, and early adoption is permitted. We will become effective beginning with our 2018 reporting year. We are evaluatingevaluate the impact of this standard.standard, if applicable.


Leases
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In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard.


Note 2:Sinclair Acquisition


Note 2:Acquisitions


El Dorado Tank FarmHEP Transaction

On March 6, 2015, we completed14, 2022, pursuant to the acquisition of an existing crude tank farm adjacent to HFC's El Dorado Refinery from an unrelated third-party for $27.5 million in cash. SubstantiallyContribution Agreement, HEP acquired all of the purchaseoutstanding equity interests of Sinclair Transportation in exchange for 21 million newly issued HEP Units, representing 16.6% of the pro forma outstanding HEP Units with a value of approximately $349 million based on HEP’s fully diluted common limited partner units outstanding and closing unit price was allocatedon March 11, 2022, and cash consideration equal to properties$329 million, inclusive of final working capital adjustments pursuant to the Contribution Agreement for an aggregate transaction value of $678 million. On the same date and equipmentimmediately following the consummation of the HEP Transaction, pursuant to the Business Combination Agreement, REH Company contributed all of the equity interests of the Target Company to HF Sinclair in exchange for 60,230,036 shares of common stock in HF Sinclair,representing 27% of the pro forma equity of HF Sinclair with a value of approximately $2,149 million based on HF Sinclair’s fully diluted shares of common stock outstanding and no goodwill was recorded. HFC is the main customer of this crude tank farm.closing stock price on March 11, 2022.

Frontier Pipeline
On August 31, 2015, we purchased2, 2021, in connection with the Contribution Agreement, HEP, Holly Logistics Services, L.L.C., the ultimate general partner of HEP (“HLS”) and Navajo Pipeline Co., L.P., the sole member of HLS (the “Sole Member”), entered into a 50% interest in Frontier Aspen (formerly known as Frontier Pipeline Company)unitholders agreement (the “Unitholders Agreement”) by and among HEP, HLS, the Sole Member, REH Company and the stockholders of REH Company (each a “Unitholder” and collectively, the “Unitholders,” and along with REH Company and each of their permitted transferees, the “REH Parties”), which owns a 289-mile crude oil pipeline running from Casper, Wyoming to Frontier Station, Utah (the "Frontier Pipeline"), from an affiliate of Enbridge, Inc. for cash consideration of $54.6 million. As described below,became effective on October 31, 2017, we acquired the remaining 50% interest in this entity. The Frontier Pipeline supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connectionClosing Date.

Pursuant to the SLC Pipeline.Unitholders Agreement, the REH Parties have the right to nominate, and have nominated, one person to the board of directors of HLS until such time that (x) the REH Parties beneficially own less than 10.5 million HEP Units or (y) the HEP Units beneficially owned by the REH Parties constitute less than 5% of all outstanding HEP Units. The Unitholders Agreement also subjects 15.75 million of the HEP Units issued to the REH Parties (the “Restricted Units”) to a “lock-up” period commencing on the Closing Date, during which the REH Parties are prohibited from selling the Restricted Units, except for certain permitted transfers. One-third of such Restricted Units were released from such restrictions on the date that was six months after the closing, one-third of the Restricted Units will be released from such restrictions on the first anniversary of the Closing Date, and the remainder will be released from such restrictions on the date that is 15 months from the Closing Date.


El Dorado Operating
On November 1, 2015, weUnder the terms of the Contribution Agreement, HEP acquired fromSinclair Transportation, which together with its subsidiaries, owned REH Company’s integrated crude and refined products pipelines and terminal assets, including approximately 1,200 miles of integrated crude and refined product pipelines supporting the REH Company refineries and other third-party refineries, eight product terminals and two crude terminals with approximately 4.5 million barrels of operated storage. In addition, HEP acquired Sinclair Transportation’s interests in three pipeline joint ventures for crude gathering and product offtake including: Saddle Butte Pipeline III, LLC (25.06% non-operated interest); Pioneer Pipeline (49.995% non-operated interest); and UNEV Pipeline (the 25% non-operated interest not already owned by HEP, resulting in UNEV Pipeline, LLC becoming a wholly owned subsidiary of HFC, all the outstanding membership interests in El Dorado Operating LLC (“El Dorado Operating”), which owns the newly constructed naphtha fractionation and hydrogen generation units at HFC’s El Dorado refinery, for cash consideration of $62.0 million. In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC that provide minimum annualized revenues of $15 million as of the acquisition date. As we are a consolidated VIE of HFC, this transactionHEP).

The HEP Transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis in El Dorado Operating’s assets and liabilities.

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

Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we agreed to build two connections on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. These connections were in service in the fourth quarter of 2017. Effective upon the closing of this exchange, we are the named operator of the Osage Pipeline and transitioned into that role on September 1, 2016. Since we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis of its 50% membership interest in Osage of $44.5 million offset by our net carrying basis in the El Paso terminal of $12.1 million with the difference recorded as a contribution from HFC. However, since these transactions were concurrent, there was no impact on periods prior to February 22, 2016.

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

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


Woods Cross Operating
Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross refinery, for cash consideration of $278 million. The consideration was funded with $103 million in proceeds from a 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 that provide minimum annualized revenues of $57 million as of the acquisition date. As we are a consolidated variable interest entity (“VIE”) of HFC, this transaction was recorded as a transfer between entities under common control and reflect HFC’s carrying basis in the net assets acquired.

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

These acquisitions were accounted for as a business combination achieved in stages. Our preexisting equityusing the acquisition method investments in SLC Pipelineof accounting, with the assets acquired and Frontier Aspen were remeasuredliabilities assumed at antheir respective acquisition date fair value of $112 million since we now have a controlling interest, and we recognized a gain onvalues at the remeasurementClosing Date, with the excess consideration recorded as goodwill. The preliminary purchase price allocation resulted in the fourth quarterrecognition of 2017 of $36.3 million. The fair value of our preexisting equity method investments$119.1 million in SLC Pipeline and Frontier Aspen was estimated using Level 3 Inputs under the income method for these entities, adjusted for lack of control and marketability.goodwill.

The total consideration of $362 million, consisting of cash consideration of $250 million and the fair value of our preexisting equity method investments in SLC Pipeline and Frontier Aspen of $112 million, was allocated to the acquisition date fair value of assets and liabilities acquired as of the October 31, 2017 acquisition date, with the excess purchase price recorded as goodwill.


The following summarizestables present the value of assetspurchase consideration and liabilities acquired:

 (in thousands)
Cash and cash equivalents$4,609
Accounts receivable4,919
Prepaid and other current assets253
Properties and equipment277,016
Intangible assets70,182
Goodwill10,218
Accounts payable(3,694)
Accrued property taxes(1,438)
Other current liabilities(65)
Net assets acquired$362,000


We have assigned a preliminary estimate of fair valuepurchase price allocation to the assets acquired and liabilities assumed on March 14, 2022:

Purchase Consideration (in thousands except for per share amounts)
HEP common units issued21,000 
Closing price per unit of HEP common units(1)
$16.62 
Purchase consideration paid in HEP common units349,020 
Cash consideration paid by HEP325,000 
Working capital adjustment payment by HEP(2)
3,955 
Total cash consideration328,955 
Total purchase consideration$677,975 
(1) Based on the HEP closing unit price on March 11, 2022.
(2) Net of cash acquired
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(In thousands)
Assets Acquired
Accounts receivable3,005 
Prepaid and other current assets59 
Properties and equipment340,682 
Operating lease right-of-use assets105 
Other assets3,500 
Goodwill119,112 
Equity method investments229,891 
Total assets acquired696,354 
Liabilities Assumed
Accounts payable1,528 
Accrued property taxes973 
Other current liabilities789 
Operating lease liabilities33 
Noncurrent operating lease liabilities72 
Other long-term liabilities14,984 
Total liabilities assumed18,379 
Net assets acquired677,975 

The fair value of properties, plants and equipment was based on the combination of the cost and market approaches. Key assumptions in the cost approach include determining the replacement cost by evaluating recently published data and adjusting replacement cost for physical deterioration, functional and economic obsolescence. We used the market approach to measure the value of certain assets through an analysis of recent sales or offerings of comparable properties.

The fair value of the equity method investments were based on a combination of valuation methods including discounted cash flows and the guideline public company method.

The fair values discussed above were based on significant inputs that are not observable in the market and, therefore, represent Level 3 measurements. See Note 6.

The fair values of all other current receivable and payables were equivalent to their carrying values due to their short-term nature.

These fair value estimates are preliminary and, therefore, the final fair values of assets acquired and liabilities assumed and the resulting effect on our allocationfinancial position may change once all needed information has become available, and we completefinalize our valuations.


Our consolidated financial and operating results reflectfor the SLC Pipeline and Frontier Aspenyear ended December 31, 2022 reflected the Sinclair Transportation operations beginning November 1, 2017.March 14, 2022. Our results of operations for the year ending December 31, 2017 included revenues of $7.9 millionrevenue, interest income from sales-type leases and net income of $4.1$28.3 million, excluding the $36.3$52.0 million remeasurement gain as of the acquisition date discussed above,and $58.1 million, respectively, for the period from November 1, 2017March 14, 2022 through December 31, 2017.2022, related to these operations.
SLC Pipeline is
For the owneryear ended December 31, 2022, we incurred $2.4 million in incremental direct acquisition and integration costs that principally relate to legal, advisory and other professional fees and are presented as general and administrative expenses in our statements of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal of the Frontier Pipeline and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.operations.


The following unaudited pro forma combined condensed financial information combinesdata for the years ended December 31, 2022 and 2021 was derived from our historical operations offinancial statements giving effect to the HEP SLC Pipeline and Frontier AspenTransaction as if the acquisitionit had occurred on January 1, 2016:

2021. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the depreciation of Sinclair Transportation’s fair-valued properties, plants and equipment.
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  Years Ended December 31,
  2017 2016
  (in thousands)
Revenues $489,382
 $445,017
Net income attributable to the partners $161,900
 $162,862


Additionally, pro forma earnings include certain non-recurring charges, the substantial majority of which consist of transaction costs related to financial advisors, legal advisors, financial advisory and professional accounting services.

The unaudited pro forma net income attributableresults of operations do not include any contract adjustments to tariffs made after closing, cost savings or other synergies that may result from the HEP Transaction. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the HEP Transaction taken place on January 1, 2021 and is not intended to be a projection of future results.

Years Ended December 31,
20222021
Sales and other revenues562,242 565,115 
Net income attributable to the partners218,006 240,509 

Contemporaneous with the closing of the Sinclair Transactions, HEP and HFC amended certain intercompany agreements, including the master throughput agreement, to include within the scope of such agreements certain of the assets acquired by HEP pursuant to the partners reflectsContribution Agreement.
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Note 3:Investment in Joint Venture

On October 2, 2019, HEP Cushing LLC (“HEP Cushing”), a wholly owned subsidiary of HEP, and Plains Marketing, L.P. (“PMLP”), a wholly owned subsidiary of Plains All American Pipeline, L.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for (i) the development and construction of a new 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that connected the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HF Sinclair, 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 during the third quarter of 2021. Long-term commercial agreements were entered into to support the Cushing Connect Joint Venture assets.

The Cushing Connect Joint Venture contracted with an affiliate of HEP to manage the construction and operation of the Cushing Connect Pipeline and with an affiliate of Plains to manage the operation of the Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment was generally shared equally among the partners. However, we were solely responsible for any Cushing Connect Pipeline construction costs that exceeded the budget by more than 10%. HEP's share of the cost of the Cushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline construction costs was approximately $74 million, including approximately $5 million of Cushing Connect Pipeline construction costs that exceeded the budget by more than 10% borne solely by HEP.

The Cushing Connect Joint Venture legal entities are variable interest entities (“VIEs”) as defined under GAAP. A VIE is a legal entity if it has any one of the following adjustments: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 group, lack the characteristics of a controlling financial interest; or (iii) the entity is structured with non-substantive voting rights. The Cushing Connect Joint Venture legal entities did not have sufficient equity at risk to finance their activities without additional financial support. Since HEP constructed and is operating 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 the Cushing Connect JV Terminal legal entity using the equity method of accounting. HEP's maximum exposure to loss as a result of its involvement with the Cushing Connect JV Terminal legal entity is not expected to be material due to the long-term terminalling agreements in place to support its operations.


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 extent of HEP Cushing's assets, which other than its investment in Cushing Connect Joint Venture, are not significant. Furthermore, our creditors have no recourse to the assets of the Cushing Connect Joint Venture legal entities.


Note 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 are as follows:
Years Ended December 31,
202220212020
(In thousands)
Pipelines$285,451 $263,110 $265,834 
Terminals, tanks and loading racks167,812 142,267 151,692 
Refinery processing units94,217 89,118 80,322 
$547,480 $494,495 $497,848 
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Affiliates and third parties revenues on our consolidated statements of income were composed of the following lease and service revenues:
Years Ended December 31,
202220212020
(In thousands)
Lease revenues$333,627 $336,062 $360,598 
Service revenues213,853 158,433 137,250 
$547,480 $494,495 $497,848 
A contract liability exists when an entity is obligated to perform future services to a customer for which the entity has received consideration. Since HEP may be required to perform future services for 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 in the table below.
December 31,
2022		December 31,
2021
 (In thousands)
Contract assets$6,672 $6,637 
Contract liabilities$— $(4,185)

The contract assets and liabilities include both lease and service components. During the years ended December 31, 2022 and 2021, we recognized $4.2 million and $0.5 million, respectively, of revenue that was previously included in contract liability as of December 31, 2021 and 2020, respectively. During the twelve months ended December 31, 2022 and 2021, we also recognized $0.2 million and $0.3 million, respectively, of revenue included in contract assets at December 31, 2022 and 2021, respectively.
As of December 31, 2022, we expect to recognize $1.5 billion in revenue related to our unfulfilled performance obligations under the terms of our long-term throughput agreements and operating leases expiring in 2023 through 2037. These agreements provide for changes in the minimum revenue guarantees annually for increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index, with certain contracts having provisions that limit the level of the rate increases or decreases. We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and lease revenues):
Years Ending December 31,(In millions)
2023301 
2024265 
2025184 
2026169 
2027136 
Thereafter401 
Total$1,456 
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

Lessee Accounting
As a lessee, we lease land, buildings, pipelines, transportation and other equipment to support our operations. These leases can be categorized into operating and finance leases.
Our leases have remaining terms of less than 1 year to 22 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 $7.6 million and $6.0 million as of December 31, 2022 and December 31, 2021, respectively, with accumulated depreciation of $4.0 million and $3.6 million as of December 31, 2022 and December 31, 2021, respectively. We include depreciation of finance leases in depreciation and amortization in our consolidated statements of income.

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

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Supplemental balance sheet information related to leases was as follows (in thousands, except for lease term and discount rate):
December 31, 2022December 31, 2021
Operating leases:
   Operating lease right-of-use assets, net$2,317 $2,275 
   Current operating lease liabilities968 620 
   Noncurrent operating lease liabilities1,720 2,030 
      Total operating lease liabilities$2,688 $2,650 
Finance leases:
   Properties and equipment$7,649 $6,031 
   Accumulated amortization(3,979)(3,632)
      Properties and equipment, net$3,670 $2,399 
   Current finance lease liabilities4,389 3,786 
   Noncurrent finance lease liabilities62,513 64,649 
      Total finance lease liabilities$66,902 $68,435 
Weighted average remaining lease term (in years)
   Operating leases4.65.8
   Finance leases13.915.0
Weighted average discount rate
   Operating leases4.6%4.8%
   Finance leases5.7%5.6%

Supplemental cash flow and other information related to leases were as follows:
Year Ended
December 31, 2022		Year Ended December 31, 2021
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows on operating leases$1,062 $1,142 
Operating cash flows on finance leases$4,255 $4,104 
Financing cash flows on finance leases$3,743 $3,549 

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Maturities of lease liabilities were as follows:
December 31, 2022
OperatingFinance
(In thousands)
2023$1,028 $7,925 
2024608 7,504 
2025491 7,044 
2026326 7,165 
2027205 6,448 
2027 and thereafter318 61,038 
   Total lease payments2,976 97,124 
Less: Imputed interest(288)(30,222)
   Total lease obligations2,688 66,902 
Less: Current lease liabilities(968)(4,389)
   Long-term lease liabilities$1,720 $62,513 

The components of lease expense were as follows:
Years Ended December 31,
20222021
(In thousands)
Operating lease costs$1,048 $1,077 
Finance lease costs
 Amortization of assets877 803 
 Interest on lease liabilities3,797 3,953 
Variable lease cost471 215 
Total net lease cost$6,193 $6,048 

Lessor Accounting
As discussed in Note 1, the majority of our contracts with customers meet the definition of a lease. See Note 1 for further discussion of the impact of adoption of this standard on our activities as a lessor.

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. HF Sinclair, generally has the option to purchase assets located within HF Sinclair, refinery boundaries, including refinery tankage, truck racks and refinery processing units, at fair market value when the related agreements expire.

During the year ended December 31, 2022, we entered into new agreements, and amended other agreements, with HF Sinclair, related to our newly acquired Sinclair Transportation assets. Certain of these agreements met the criteria of sales-type leases. Under sales-type lease accounting, at the commencement date, the lessor recognizes a net investment in the lease, based on the estimated fair value of the underlying leased assets at contract inception, and derecognizes the underlying assets with the difference recorded as selling profit or loss arising from the lease. Because we recorded these assets at fair values under purchase price accounting, there was no gain or loss on these sales-type leases during the year ended December 31, 2022. The balance sheet impacts were composed of the following:
(1)To retrospectively reflect depreciation and amortization of intangible assets based on the preliminary fair value of the assets as if that fair value had been reflected January 1, 2016(In thousands)
(2)Net investment in leasesTo eliminate HEP's equity income previously recorded on its equity method investments in SLC Pipeline$234,736 
Properties and Frontier Aspenequipment, net(234,736)
(3)Gain on sales-type leasesTo eliminate the remeasurement gain on preexisting equity interests in SLC Pipeline and Frontier Aspen$— 



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During the year ended December 31, 2021, we entered into new agreements, and amended other agreements, with HF Sinclair, 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-type leases. We recognized a gain on sales-type leases during the year ended December 31, 2021 composed of the following:
Note 3:(In thousands)
Net investment in leases148,419 
Properties and equipment, net(130,301)
Deferred Revenue6,559 
Gain on sales-type leases$24,677 

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

Lease income recognized was as follows:
Years Ended December 31,
20222021
(In thousands)
Operating lease revenues$310,968 $326,902 
Direct financing lease interest income2,115 2,089 
Gain on sales-type leases— 24,677 
Sales-type lease interest income89,285 27,836 
Lease revenues relating to variable lease payments not included in measurement of the sales-type lease receivable22,659 9,160 
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 recorded as interest income with the remaining amounts recorded as a reduction in net investment in leases. We recognized any billings for throughput volumes in excess of minimum volume requirements as variable lease payments, and these variable lease payments were recorded in lease revenues.

Annual minimum undiscounted lease payment receipts under our leases were as follows as of December 31, 2022:
OperatingFinanceSales-type
Years Ending December 31,(In thousands)
2023$271,439 $2,243 $103,876 
2024241,746 2,226 100,580 
2025165,560 2,244 97,153 
2026151,015 2,262 97,153 
2027118,472 2,280 97,153 
Thereafter346,975 34,940 820,234 
Total lease payment receipts$1,295,207 46,195 1,316,149 
Less: Imputed interest(29,931)(1,189,628)
16,264 126,521 
Unguaranteed residual assets at end of leases— 402,934 
Net investment in leases$16,264 $529,455 

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Net investments in leases recorded on our balance sheet were composed of the following:
December 31, 2022December 31, 2021
Sales-type LeasesDirect Financing LeasesSales-type LeasesDirect Financing Leases
(In thousands)(In thousands)
Lease receivables (1)
$418,989 $16,264 $207,768 $16,371 
Unguaranteed residual assets110,466 — 90,097 — 
Net investment in leases$529,455 $16,264 $297,865 $16,371 

(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 includes valuation techniques that involve significant unobservable inputs.

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:
(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:
 December 31, 2022December 31, 2021
Financial InstrumentFair Value Input LevelCarrying
Value		Fair ValueCarrying
Value		Fair Value
(In thousands)
Liabilities:
5% Senior NotesLevel 2$494,047 $458,090 $493,049 $502,705 
6.375% Senior NotesLevel 2394,287 394,568 — — 
Total Liabilities$888,334 $852,658 $493,049 $502,705 
    December 31, 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:          
6.0% Senior Notes Level 2 $495,308
 $525,120
 $393,393
 $415,500
6.5% Senior Notes Level 2 —
 —
 297,519
 308,250
    $495,308
 $525,120
 $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
The HEP Transaction was accounted for as a business combination using the acquisition method of accounting, with the assets acquired and the liabilities assumed at their respective acquisition date fair values at the Closing Date. The fair value
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measurements were based on a combination of valuation methods including discounted cash flows, the guideline public company method, the market approach and obsolescence adjusted replacement costs, all of which are Level 3 inputs.

For the net investments in sales-type leases recognized during the years ended December 31, 2022 and 2021, the estimated fair value of the underlying leased assets at contract inception and the present value of the estimated unguaranteed residual asset at the end of the lease term are used in determining the net investment in leases and related gain on sales-type leases recorded. The asset valuation estimates include Level 3 inputs based on a replacement cost valuation method.

During the years ended December 31, 2021 and 2020, 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 variable and fixed-rate legsthe guideline public company and guideline transaction methods; 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 7 for additional information on these instruments.7:Properties and Equipment


Note 4:
Properties and Equipment


The carrying amounts of our properties and equipment are as follows:
December 31,
2022		December 31,
2021
 (In thousands)
Pipelines, terminals and tankage$1,567,359 $1,527,697 
Refinery assets353,998 348,882 
Land and right of way171,327 98,837 
Construction in progress23,027 26,446 
Other69,098 48,203 
2,184,809 2,050,065 
Less accumulated depreciation(795,921)(721,037)
$1,388,888 $1,329,028 
  December 31,
2017		 December 31,
2016
  (In thousands)
Pipelines, terminals and tankage $1,541,722
 $1,246,746
Refinery assets 347,338
 346,058
Land and right of way 86,484
 65,331
Construction in progress 12,029
 28,753
Other 35,659
 27,133
  2,023,232
 1,714,021
Less accumulated depreciation 453,761
 385,626
  $1,569,471
 $1,328,395
We capitalized $1.0 million and $0.7 million in interest related to construction projects during the years ended December 31, 2017 and 2016, respectively.

Depreciation expense was $71.1$80.9 million, $62.9$79.2 million,, and $55.8$85.0 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively, and includes depreciation of assets acquired under capital leases. Asset abandonment charges of $0.3$0.1 million, $0.6$1.1 million and $1.1$1.0 million for assets permanently removed from service were included in depreciation expense for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.




Note 5:Intangible Assets

Note 8:Intangible Assets

Intangible assets include transportation agreements and customer relationships that represent a portion of the total purchase price of certain assets acquired from Delek in 2005,, from HFC in 2008 prior to HEP becoming a consolidated VIE of HFC, and from Plains in 2017.2017, and from other minor acquisitions in 2018.


The carrying amounts of our intangible assets are as follows:
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 Useful Life December 31,
2017		 December 31,
2016		Useful LifeDecember 31,
2022		December 31,
2021
 (In thousands) (In thousands)
Delek transportation agreement 30 years $59,933
 $59,933
Delek transportation agreement30 years$59,933 $59,933 
HFC transportation agreements 10-15 years 75,131
 74,231
HF Sinclair transportation agreementsHF Sinclair transportation agreements10-15 years75,131 75,131 
Customer relationships 10 years 69,282
 —
Customer relationships10 years69,683 69,683 
Other 50
 50
Other20 years50 50 
 204,396
 134,214
204,797 204,797 
Less accumulated amortization 74,933
 67,358
Less accumulated amortization(145,497)(131,490)
 $129,463
 $66,856
Intangible assets, netIntangible assets, net$59,300 $73,307 



Amortization expense was $7.6 million for the year ended December 31, 2017, and $6.9$14.0 million for the years endingended December 31, 20162022, 2021 and 2015.2020, respectively. We estimate amortization expense to be $14$9.9 million for each of the next five years.2023, and $9.1 million for 2024, 2025, 2026 and 2027.


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




Note 6: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"(“HLS”), an HFCHF Sinclair subsidiary, which utilizes personnel employed by HFCHF Sinclair 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.HF Sinclair. These employees participate in the retirement and benefit plans of HFC.HF Sinclair. Our share of retirement and benefit plan costs was $5.9$11.2 million, $5.7$8.7 million and $5.4$7.9 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively. These costs include retirement costs of $2.7$4.9 million, $2.6$3.7 million and $2.2$3.4 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.


Under HLS’s secondment agreement with HFCHF Sinclair (the “Secondment Agreement”), certain employees of HFCHF Sinclair are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFCHF Sinclair 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 fourfive 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 December 31, 2017,2022, we have two types of incentive-basedunit-based awards outstanding, which are described below. The compensation cost charged against income was $2.7$1.9 million, $2.7$2.6 million and $3.4$2.2 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, 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 December 31, 2017, 2022, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,338,743773,014 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.


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


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

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A summary of restricted and phantom unit activity and changes during the year ended December 31, 2017,2022, is presented below:
Phantom UnitsUnitsWeighted-
Average
Grant-Date
Fair Value
Outstanding at January 1, 2022 (nonvested)203,263 $14.85 
Granted84,705 18.57 
Vesting and transfer of common units to recipients(105,031)16.88 
Forfeited(67,128)13.26 
Outstanding at December 31, 2022 (nonvested)115,809 16.66 
Restricted and Phantom Units Units 
Weighted-
Average
Grant-Date
Fair Value
Outstanding at January 1, 2017 (nonvested) 123,988
 $32.96
Granted 81,883
 35.59
Vesting and transfer of common units to recipients (59,241) 33.97
Forfeited (27,621) 30.79
Outstanding at December 31, 2017 (nonvested) 119,009
 $34.77



The grant date fair values of restricted or phantom units that were vested and transferred to recipients during the years ended December 31, 2017, 20162022, 2021 and 20152020 were $1.8 million, $2.1 million and $2.0 million,$2.0 million and $2.5 million respectively. As of December 31, 2017,2022, there was $2.9$1.3 million of total unrecognized compensation expense related to unvested restricted and phantom unit grants, which is expected to be recognized over a weighted-average period of 1.61.3 years. For the years ended December 31, 20162021 and 2015,2020, the grant date price applied to the number of restricted or phantom units awarded was $32.16$18.93 and $34.16$11.92, respectively.


Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted are payable in common units at the end of a three-yearthree-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 December 31, 2017, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target number of performance units granted.

We granted 10,881 performance units during the year ended December 31, 2017. Performance units granted in 2016 and 2017 vest over a three-year performance period ending December 31, 2019 and 2020, respectively, and are payable intotal unitholder return achieved by HEP common units.compared to peer group companies. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, andultimately issued under these awards can range from 50%0% to 150% of the target number of performance units granted. 200%.

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. The fair value of these performance units is basedgrant at the same rate as distributions paid on the grant date closing unit price of $35.62 and will apply to the number of units ultimately awarded. For the year ended December 31, 2016, the grant date closing unit price applied to the number of units awarded was $24.48 and $33.33 for the performance units granted in February and October, respectively, and for the year ended December 31, 2015, the grant date closing unit price was $34.21.our common units.


A summary of performance unit activity and changes for the year ended December 31, 2017,2022, is presented below:
Performance UnitsUnits
Outstanding at January 1, 20172022 (nonvested)49,52076,719 
Granted10,88110,698 
Vesting and transfer of common units to recipients(2,262(35,441))
Forfeited(21,228(9,124))
Outstanding at December 31, 20172022 (nonvested)36,91142,852 


The grant date fair valuevalues of performance units vested and transferred to recipients was $0.1were $0.8 million, $0.4 million and $0.4 million for the yearyears ended December 31, 2017, $1.1 million for the year ended December 31, 2016,2022, 2021 and $0.5 million for the year ended December 31, 2015.2020, respectively. Based on the weighted average fair value of performance units outstanding at December 31, 2017,2022, of $1.3$0.7 million, there was $0.9$0.5 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.6 years. 1.7 years.


During the year ended December 31, 2017,2022, we did notpaid $1.7 million for the purchase anyof our common units in the open market for the issuance and settlement of all unit awards under our Long-Term Incentive Plan.




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Note 7:Debt


Note 10:Debt

Credit Agreement
In July 2017,April 2021, we amended our senior secured revolving credit facility (the “Credit Agreement”) increasingdecreasing the size of the Credit Agreementfacility from $1.2$1.4 billion to $1.4$1.2 billion and extending the expirationmaturity date to July 2022.27, 2025. In August 2022, the Credit Agreement was amended to, among other things, provide an alternative reference rate for LIBOR. 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. Indebtednessassets, 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.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.50% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.50% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). The weighted-average interest rates on our Credit Agreement borrowings in effect at December 31, 2017 and 2016, were 3.734% and 2.978%, respectively. We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.


We may prepay all loans at any time without penalty, except for tranche breakage costs. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercisingexercise other rights and remedies. We were in compliance with the covenants as of December 31, 2017.2022.


Senior Notes
On July 19, 2016,April 8, 2022, we closed a private placement of $400 million in aggregate principal amount of 6%6.375% senior unsecured notes due in 20242027 (the “6%“6.375% Senior Notes”). On September 22, 2017, we closed a private placementThe 6.375% Senior Notes were issued at par for net proceeds of an additional $100approximately $393 million, in aggregateafter deducting the initial purchasers’ discounts and commissions and estimated offering expenses. The total net proceeds from the offering of the 6%6.375% Senior Notes for a combinedwere used to partially repay outstanding borrowings under the Credit Agreement, increasing our available liquidity.

As of December 31, 2022, we had $500 million aggregate principal amount outstanding of $500 million maturing5% senior unsecured notes due in 2024.2028 (the “5% Senior Notes,” and together with the 6.375% Senior Notes, the “Senior Notes”).


The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of December 31, 2017. At any time when the 6% 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% Senior Notes.


Indebtedness under the 6% 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.
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Our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under these agreements, we are restricted from prepaying borrowings and long-term debt to below $171 million prior to 2018, subject to certain limited exceptions.


Long-term Debt
The carrying amounts of our long-term debt are as follows:
December 31,
2022		December 31,
2021
(In thousands)
Credit Agreement
Amount outstanding$668,000 $840,000 
 5% Senior Notes
Principal500,000 500,000 
Unamortized premium and debt issuance costs(5,953)(6,951)
494,047 493,049 
 6.375% Senior Notes
Principal400,000 — 
Unamortized premium and debt issuance costs(5,713)— 
394,287 — 
Total long-term debt$1,556,334 $1,333,049 
  December 31,
2017		 December 31,
2016
  (In thousands)
Credit Agreement    
Amount outstanding $1,012,000
 $553,000
     
6% Senior Notes    
Principal 500,000
 400,000
Unamortized debt issuance costs (4,692) (6,607)
  495,308
 393,393
6.5% Senior Notes    
Principal —
 300,000
Unamortized discount and debt issuance costs —
 (2,481)
  —
 297,519
     
Total long-term debt $1,507,308
 $1,243,912


Maturities of our long-term debt are as follows:
Years Ending December 31, (In thousands)
2018 $—
2019 —
2020 —
2021 —
2022 1,012,000
Thereafter 500,000
Total $1,512,000

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

Additional information on our interest rate swaps is as follows:
Derivative Instrument Balance Sheet Location Fair Value Location of Offsetting Balance 
Offsetting
Amount
  (In thousands)
December 31, 2016        
Interest rate swaps designated as cash flow hedging instrument:      
Variable-to-fixed interest rate swap contract ($150 million of LIBOR based debt interest) Other current
    assets		 $91
 
Accumulated other
    comprehensive loss
 $91
    $91
   $91
         


Interest Expense and Other Debt Information
Interest expense consists of the following components:
  Years Ended December 31,
  2017 2016 2015
  (In thousands)
Interest on outstanding debt:      
Credit Agreement, net of interest on interest rate swaps $28,928
 $17,621
 $16,107
6% Senior Notes 25,813
 10,811
 —
6.5% Senior Notes —
 19,507
 19,507
Amortization of discount and deferred debt issuance costs 3,063
 3,246
 1,928
Commitment fees and other 1,648
 2,069
 638
Total interest incurred 59,452
 53,254
 38,180
Less capitalized interest 1,004
 702
 762
Net interest expense $58,448
 $52,552
 $37,418
Cash paid for interest $62,395
 $38,530
 $35,938

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 $5.1 million and $4.9 millionfollows as of December 31, 2017 and 2016, respectively, with accumulated depreciation of $3.3 million and $2.4 million as of December 31, 2017 and 2016, respectively. We include depreciation of capital leases in depreciation and amortization in our consolidated statements of income.2022:

Years Ending December 31,(In thousands)
2023$— 
2024— 
2025668,000 
2026— 
2027400,000 
Thereafter500,000 
Total$1,568,000 
At December 31, 2017, future minimum annual lease payments, including interest, for the capital leases are as follows:

Years Ending December 31,(in thousands)
2018$1,019
2019765
2020228
2021—
   Total minimum lease payments2,012
Less amount representing interest(129)
   Capital lease obligations$1,883


Note 8:Commitments and Contingencies

Note 11:Commitments and Contingencies

We lease certain facilities and pipelines under operating leases and finance leases, most of which contain renewal options. These operating leases have various termination dates through 2027.

2041. See Note 5 for a schedule of annual minimum undiscounted lease payments under our leases as of December 31, 2022. As of December 31, 2017, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:
Years Ending December 31,(In thousands)
2018$7,278
20196,861
20206,805
20216,755
20226,753
Thereafter29,861
Total$64,313

Rental expense charged to operations was $9.1 million, $8.5 million and $8.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017,2022, we expect to receive aggregate payments totaling $1.6$0.8 million over the life of our noncancelable sublease of office space, expiring in 2026.
We also have other long-term contractual obligations consisting of long-term site service agreements with HFC,HF Sinclair, expiring in 2058 through 2066, for the provision of certain facility services and utility costs that relate to our assets located at HFC’sHF Sinclair’s refinery and renewable diesel facilities. We are presenting obligations for the full term of these agreements; however, the agreements can be terminated with 180 day notice if we cease to operate the applicable assets.
In addition, we have long-term contractual obligations associated with rights-of-way agreements, which have various termination dates through 2061.2099. The related payments below include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2017.2022.
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At December 31, 2017,2022, these minimum future contractual obligations and other miscellaneous obligations having terms in excess of one year are as follows:
Years Ending December 31,(In thousands)
2018$5,616
20195,559
20205,385
20215,380
20225,375
Thereafter223,331
Total$250,646
Years Ending December 31,(In thousands)
2023$8,856 
20248,803 
20257,030 
20265,944 
20275,943 
Thereafter214,367 
Total$250,943 
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 9:Significant Customers

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

The following table presents the percentage of total revenues generated by each of these customers:
 Years Ended December 31,
 2017 2016 2015
HFC83% 83% 81%
Delek8% 8% 10%


Note 10:Related Party Transactions

Note 12:Related Party Transactions

We serve HFC’s refineriesmany of HF Sinclair’s refinery and renewable diesel facilities under long-term pipeline, terminal and tankage throughput agreements, and refinery processing unit tolling agreements expiring from 20192023 to 2036.2037, and revenues from these agreements accounted for approximately 80% of our total revenues for the year ended December 31, 2022. Under these agreements, HFCHF Sinclair 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 generally subject to annual rate adjustments on July 1st each year based on increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”)FERC index. As of December 31, 2017,2022, these agreements with HFCHF Sinclair require minimum annualized payments to us of $324$452.6 million.


If HFCHF Sinclair 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 HFCHF Sinclair an annual administrative fee ($2.5 million in 2017)(currently $5.0 million) for the provision by HFCHF Sinclair or its affiliates of various general and administrative services to us. ThisIn connection with the HEP Transaction, we paid HF Sinclair a temporary monthly fee does not includeof $62,500 from the Closing Date through November 30, 2022, relating to transition services provided to HEP by HF Sinclair. Neither the annual administrative fee nor the temporary monthly fee includes the salaries of personnel employed by HFCHF Sinclair who perform services for us on behalf of HLS or the cost of their employee benefits, which are charged to us separately by HFC.HF Sinclair. Also, we reimburse HFCHF Sinclair and its affiliates for direct expenses they incur on our behalf.


Related party transactions with HFCHF Sinclair are as follows:
•Revenues received from HFCHF Sinclair were $377.1$438.3 million, $333.1$390.8 million and $292.2$399.8 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.
HFC•HF Sinclair charged us general and administrative services under the Omnibus Agreement of $2.5$4.5 million for the year ended December 31, 2017, $2.52022 and $2.6 million for each of the yearyears ended December 31, 2016,2021 and $2.4 million for the year ended December 31, 2015.2020.
•We reimbursed HFCHF Sinclair for costs of employees supporting our operations of $46.6$78.2 million, $40.9$61.2 million and $34.5$55.8 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.
HFC•HF Sinclair reimbursed us $7.2$14.7 million, $14.0$7.9 million and $13.5$10.0 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively, for expense and capital projects.
•We distributed $130.7$83.5 million $105.2 million and $90.4 million, forin each of the years ended December 31, 2017, 20162022 and 2015, respectively,2021 and $95.2 million in the year ended December 31, 2020 to HFCHF Sinclair as regular distributions on its common units and general partner interest, including general partner incentive distributions.
units.
•Accounts receivable from HFCHF Sinclair were $51.5$63.5 million and $42.6$56.2 million at December 31, 20172022 and 2016,2021, respectively.
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•Accounts payable to HFCHF Sinclair were $7.7$15.8 million and $16.4$11.7 million at December 31, 20172022 and 2016,2021, respectively.
•Revenues for the years ended December 31, 2017, 20162022, 2021 and 20152020 include $4.8$0.4 million, $6.1$0.4 million and $7.3$0.5 million,, respectively, of shortfall payments billed to HF Sinclair in 2016, 20152021, 2020 and 2014,2019, respectively. Deferred revenue in the consolidated balance sheets at December 31, 2017 and 2016,2021, includes $4.4$4.1 million, and $5.6 million, respectively, relating to certain shortfall billings. It is possible that HFC may not exceed its minimum obligationsbillings to receive credit for any of the $4.4 million deferred as of December 31, 2017.
HF Sinclair.
•We received operatingdirect financing lease payments from HFCHF Sinclair for use of our Artesia and Tulsa railyards of $0.5$2.2 million for the year ended December 31, 2022 and $2.1 million for each of the years ended December 31, 2017, 20162021 and 2015.2020.

In November 2015, we acquired from HFC all•We recorded a gain on sales-type leases with HF Sinclair of $24.7 million during the outstanding membership interests in El Dorado Operating which owns the newly constructed naphtha fractionationyear ended December 31, 2021, and hydrogen generation units at HFC’s El Dorado refinery. See Note 2 for a description of this transaction.
On February 22, 2016, HFC obtained a 50% membership interest in Osage in a non-monetary exchange, whereby a subsidiary of Magellan will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received sales-type lease payments of $91.6 million, $28.9 million and $9.5 million from HF Sinclair that were not included in revenues for the years ended December 31, 2022, 2021 and 2020, respectively.
•HEP and HFC reached an agreement to terminate the existing minimum volume commitments for HEP's Cheyenne assets and enter into new agreements, which were finalized and executed on February 8, 2021, with the following terms, in each case effective January 1, 2021: (1) a ten-year lease with two five-year renewal option periods for HFC’s interest(and now HF Sinclair's) use of certain HEP tank and rack assets in Osage in exchangethe 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 (and now HF Sinclair) will pay a base tariff to HEP for our El Paso terminal. See Note 2 for a description of this transaction.
On March 31, 2016, we acquiredavailable crude oil tanks located at HFC’s Tulsa refinery from an affiliatestorage and HFC (and now HF Sinclair) and HEP will split any profits generated on crude oil contango opportunities and (3) HFC paid a $10 million one-time cash payment to HEP for the termination of Plains for $39.5 million. See Note 2 for a descriptionthe existing minimum volume commitment.
Contemporaneous with the closing of this transaction.
Effective October 1, 2016, wethe Sinclair Transactions, HEP and HFC amended certain intercompany agreements, including the master throughput agreement, to include within the scope of such agreements certain of the assets acquired all the membership interests of Woods Cross Operating, a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross refinery, for cash consideration of $278 million. See Note 2 for a description of this transaction.
On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics, a wholly-owned subsidiary of HFC and the general partner ofby HEP pursuant to which the incentive distribution rights held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions.Contribution Agreement.






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

Note 13: Partners’ Equity, Income Allocations and Cash Distributions

At December 31, 2017, HFC2022, HF Sinclair held 59,630,030 of our common units, constituting a 59%47% limited partner interest in us and held the non-economic general partner interest. Additionally, HFC owned all incentive distribution rights through October 31, 2017, when an agreement was reached with HEP Logistics, our general partner, impacting its equity interest in HEP including canceling these incentive distribution rights. See Note 1 for a description of this equity restructuring transaction.

Common Unit Private Placements
On September 16, 2016, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,420,000 common units representing limited partnership interests, at a price of $30.18 per common unit. The private placement closed on October 3, 2016, and we received proceeds of approximately $103 million, which were used to finance a portion of the Woods Cross acquisition discussed in Note 2.

On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partnership interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under our Credit Agreement. After this common unit issuance, HFC owns a 57% limited partner interest in us.


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. As of December 31, 2017,2022, HEP hashad issued 2,241,9072,413,153 units under this program, providing $77.1$82.3 million in gross proceeds. No units were issued under the program during the year ended December 31, 2022.

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 limitedthe 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 equity restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred on October 31, 2017. After this restructuring, the general partner interest is no longer entitled to any distributions. As a result of this transaction, no distributions will be made on the general partner interest and no net income will be allocated to the general partner after October 31, 2017.

The following table presents the allocation of the general partner interest in net income for the periods presented below:
  Years Ended December 31,
  2017 2016 2015
  (In thousands)
General partner interest in net income $919
 $3,165
 $1,936
General partner incentive distribution 34,128
 54,008
 40,401
Net loss attributable to Predecessor —
 (10,657) (2,702)
Total general partner interest in net income $35,047
 $46,516
 $39,635


Cash Distributions
We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the

quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Prior to the equity restructuring transaction discussed in Note 1, we made distributions in the manner displayed in the table below. Subsequent to the financial restructuring, distributions are made equally to all common unit holders regardless of the amount of the distribution per unit.
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  Total Quarterly Distribution Marginal Percentage Interest in Distributions
  Target Amount Unitholders General Partner
Minimum quarterly distribution $0.25 98% 2%
First target distribution Up to $0.275 98% 2%
Second target distribution above $0.275 up to $0.3125 85% 15%
Third target distribution above $0.3125 up to $0.375 75% 25%
Thereafter Above $0.375 50% 50%

On January 26, 2018,20, 2023, we announced our cash distribution for the fourth quarter of 2017 2022 of $0.6500 per$0.35 per unit. The distribution iswas payable on all common units and was paid February 14, 2018,13, 2023, to all unitholders of record on February 5, 2018. However, HEP Logistics waived $2.5 million in limited partnerJanuary 30, 2023.

We paid cash distributions due to them as discussed in Note 1.

The following table presents the allocation of our regular quarterly cash distributions to the generaltotaling $170.0 million, $149.4 million and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid$174.4 million during the periods presented below.years ended December 31, 2022, 2021 and 2020, respectively.


  Years Ended December 31,
  2017 2016 2015
  (In thousands, except per unit data)
General partner interest in distribution $2,335
 $4,088
 $3,563
General partner incentive distribution 34,128
 54,008
 40,401
Total general partner distribution 36,463
 58,096
 43,964
Limited partner distribution 206,846
 143,796
 129,192
Total regular quarterly cash distribution $243,309
 $201,892
 $173,156
Cash distribution per unit applicable to limited partners $2.5475
 $2.3625
 $2.2025

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


Note 12:Net Income Per Limited Partner Unit

Note 14: 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 since we had more than one classpartners, adjusted for participating securities’ share in earnings, divided by the weighted average limited partners’ units outstanding. Diluted net income per unit assumes, when dilutive, the issuance of participating securities during the periodnet incremental units from January 1, 2017 through October 31, 2017.  The classes of participating securities during this period included common units, general partnerphantom units and incentive distribution rights ("IDRs"). Due to the equity restructuring transaction described in Note 1, as of December 31, 2017, we had one class of security outstanding, commonperformance units. To the extent net income attributable to the partners exceeds or is less than cash distributions, this difference is allocated to the partners based on their weighted-average ownership percentage during the period, after consideration of any priority allocations of earnings.  Theperiod. Our dilutive securities are immaterial for all periods presented.

See Note 1 for a description of the equity restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred on October 31, 2017. After this equity restructuring, the general partner interest is no longer entitled to any distributions and none were made on the general partner interest after October 31, 2017. In connection with this equity restructuring, HEP issued 37,250,000 of its common units to HEP Logistics on October 31, 2017.

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:
Years Ended December 31,
202220212020
(In thousands, except per unit data)
Net income attributable to the partners$216,783 $214,946 $170,483 
Less: Participating securities’ share in earnings(408)(736)(387)
Net income attributable to common units216,375 214,210 170,096 
Weighted average limited partners' units outstanding122,298 105,440 105,440 
Limited partners' per unit interest in earnings - basic and diluted$1.77 $2.03 $1.61 


Note 15:Environmental
  Years Ended December 31,
  2017 2016 2015
  (in thousands)
Net income attributable to the partners $195,040
 $158,241
 $137,208
Less: General partner’s distribution declared (including IDRs) (36,463) (58,096) (43,964)
Limited partner’s distribution declared on common units (206,846) (143,796) (129,192)
Distributions in excess of net income attributable to the partners $(48,269) $(43,651) $(35,948)


  General Partner (including IDRs) Limited Partners’ Common Units Total
  (In thousands, except per unit data)
Year Ended December 31, 2017      
Net income attributable to the partners:      
Distributions declared $36,463
 $206,846
 $243,309
Distributions in excess of net income attributable to partnership (1,416) (46,853) (48,269)
Net income attributable to the partners $35,047
 $159,993
 $195,040
Weighted average limited partners' units outstanding   70,291
  
Limited partners' per unit interest in earnings - basic and diluted   $2.28
  
       
Year Ended December 31, 2016      
Net income attributable to the partners:      
Distributions declared $58,096
 $143,796
 $201,892
Distributions in excess of net income attributable to partnership (873) (42,778) (43,651)
Net income attributable to the partners $57,223
 $101,018
 $158,241
Weighted average limited partners' units outstanding   59,872
  
Limited partners' per unit interest in earnings - basic and diluted   $1.69
  
       
Year Ended December 31, 2015      
Net income attributable to the partners:      
Distributions declared $43,964
 $129,192
 $173,156
Distributions in excess of net income attributable to partnership (719) (35,229) (35,948)
Net income attributable to the partners $43,245
 $93,963
 $137,208
Weighted average limited partners' units outstanding   58,657
  
Limited partners' per unit interest in earnings - basic and diluted   $1.60
  


Note 13:Environmental

We expensed $0.5$2.0 million, $0.7$1.9 million and $3.6$1.6 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively, for environmental remediation obligations. The accrued environmental liability net of expected recoveries from indemnifying parties,related to environmental clean-up projects for which we have assumed liability or for which indemnity provided by HF Sinclair has expired reflected in our consolidated balance sheets was $6.5$19.5 million and $7.1$3.9 million atas of December 31, 20172022 and December 31, 2016,2021, respectively, of which $5.0$17.5 million and $5.4$2.4 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time.


Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFCHF Sinclair and or its subsidiaries, HF Sinclair 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 HFCHF Sinclair and its subsidiaries and occurring or existing prior to the date of such transfers. As of December 31, 2017 and December 31, 2016, our consolidated balance sheets include additional accrued environmental liabilities of $0.8 million and $0.9 million, respectively, for HFC indemnified liabilities, and other assets included equal and offsetting balances representing amounts due from HFC related to indemnifications for environmental remediation liabilities.




Note 14:Operating Segments

Note 16:Operating Segments

Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in two reportable operating segments: (1) pipelines and terminals and (2) refinery processing units. These operating segments adhere to the accounting polices used for our consolidated financial statements. For a discussion of these accounting policies and a summary of our operating segments' assets and derivation of revenue, see Note 1.


TheOur pipelines and terminals segment hasincludes our petroleum product and crude pipelines and terminal, tankage and loading rack facilities that support refining and marketing operations of HF Sinclair and other refineries in the Mid-Continent, Southwest and Northwest regions of the United States.

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Our Refinery Processing Unit segment consists of five refinery processing units at two of HF Sinclair's refining facility locations.

Pipelines and terminals have been aggregated as one reportable segment as both pipelinepipelines 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.

Years Ended December 31,
202220212020
(In thousands)
Revenues:
Pipelines and terminals - affiliate$344,063 $301,731 $319,487 
Pipelines and terminals - third-party109,200 103,646 98,039 
Refinery processing units - affiliate94,217 89,118 80,322 
Total segment revenues$547,480 $494,495 $497,848 
Segment operating income:
Pipelines and terminals(1)
$202,908 $180,965 $176,611 
Refinery processing units34,857 38,172 38,314 
Total segment operating income237,765 219,137 214,925 
Unallocated general and administrative expenses(17,003)(12,637)(9,989)
Interest expense(82,560)(53,818)(59,424)
Interest income91,406 29,925 10,621 
Loss on early extinguishment of debt— — (25,915)
Equity in earnings (losses) of unconsolidated affiliates(260)12,432 6,647 
Gain on sales-type leases— 24,677 33,834 
Gain on sale of assets and other668 6,179 8,691 
Income before income taxes$230,016 $225,895 $179,390 
Capital Expenditures:
Pipelines and terminals$33,071 $87,756 $59,108 
Refinery processing units5,893 2,239 175 
Total capital expenditures$38,964 $89,995 $59,283 
December 31, 2022December 31, 2021
(In thousands)
Identifiable assets:
Pipelines and terminals(2)
$2,152,159 $1,737,388 
Refinery processing units304,332 294,452 
Other291,011 134,027 
Total identifiable assets$2,747,502 $2,165,867 
(1)Pipelines and terminals segment operating income included goodwill impairment charges of $11.0 million and $35.7 million for the years ended December 31, 2021 and December 31, 2020, respectively.
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  Years Ended December 31,
  2017 2016 2015
  (in thousands)
Revenues:      
Pipelines and terminals - affiliate $300,232
 $300,072
 $289,258
Pipelines and terminals - third-party 77,226
 68,927
 66,654
Refinery processing units - affiliate 76,904
 33,044
 2,963
Total segment revenues $454,362
 $402,043
 $358,875
       
Segment operating income:      
Pipelines and terminals $204,970
 $204,923
 $191,451
Refinery processing units 32,509
 2,706
 (1,438)
Total segment operating income 237,479
 207,629
 190,013
Unallocated general and administrative expenses (14,323) (12,532) (12,556)
Interest and financing costs, net (57,957) (52,112) (36,892)
Loss on early extinguishment of debt (12,225) —
 —
Equity in earnings of unconsolidated affiliates 12,510
 14,213
 4,803
Gain on sale of assets and other 36,676
 677
 486
Income before income taxes $202,160
 $157,875
 $145,854
       
Capital Expenditures:      
  Pipelines and terminals $289,993
 $59,704
 $67,406
  Refinery processing units 263
 44,119
 125,715
Total capital expenditures $290,256
 $103,823
 $193,121
(2)Includes goodwill of $342.8 million and $223.7 million as of December 31, 2022 and 2021, respectively.


Note 17: Supplemental Guarantor/Non-Guarantor Financial Information
  December 31, 2017 December 31, 2016
  (in thousands)
Identifiable assets:    
  Pipelines and terminals(1)
 $1,728,074
 $1,369,756
  Refinery processing units 328,585
 342,506
Other 97,455
 171,975
Total identifiable assets $2,154,114
 $1,884,237

(1)Includes goodwill of $266.7 million and $256.5 million as of December 31, 2017 and December 31, 2016, respectively.

Note 15:Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows:
  First Second Third Fourth Total
  (In thousands, except per unit data)
Year Ended December 31, 2017          
Revenues $105,634
 $109,143
 $110,364
 $129,221
 $454,362
Operating income 51,734
 52,486
 51,736
 67,200
 223,156
Income before income taxes 27,985
 42,983
 42,992
 88,200
 202,160
Net income 27,879
 42,856
 43,061
 88,115
 201,911
Net income attributable to Holly Energy Partners 25,563
 41,335
 42,071
 86,071
 195,040
Limited partners’ per unit interest in net income – basic and diluted $0.13
 $0.36
 $0.66
 $0.96
 $2.28
Distributions per limited partner unit $0.6200
 $0.6325
 $0.6450
 $0.6500
 $2.5475
           
Year Ended December 31, 2016          
Revenues $102,010
 $94,897
 $92,610
 $112,526
 $402,043
Operating income 54,513
 47,111
 38,924
 54,549
 195,097
Income before income taxes 46,847
 39,569
 28,464
 42,995
 157,875
Net income 46,751
 39,516
 28,404
 42,919
 157,590
Net income attributable to Holly Energy Partners 42,975
 39,120
 34,785
 41,361
 158,241
Limited partners’ per unit interest in net income – basic and diluted $0.52
 $0.45
 $0.33
 $0.40
 $1.69
Distributions per limited partner unit $0.5750
 $0.5850
 $0.5950
 $0.6075
 $2.3625


Note 16:Supplemental Guarantor/Non-Guarantor Financial Information


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


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


In conjunction withAs a result of the preparationHEP Transaction, UNEV Pipeline, LLC became a 100% owned subsidiary, and it was subsequently added as a guarantor of our Condensed Consolidating Balance Sheet and Statementsthe obligations of Comprehensive IncomeHEP under the Senior Notes during the second quarter of 2022. UNEV Pipeline, LLC financial information has been included below, we identified and corrected the presentation of noncontrolling interests presented in the eliminations column in priorGuarantor Subsidiaries financial information for all periods to reflect such balances and activity within the respective guarantor and non-guarantor subsidiaries columns.presented.





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Condensed Consolidating Balance Sheet
December 31, 2022ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
ASSETS
Current assets:
Cash and cash equivalents$4,316 $4,454 $2,147 $— $10,917 
Accounts receivable— 79,689 1,453 (1,339)79,803 
Prepaid and other current assets256 12,141 356 (356)12,397 
Total current assets4,572 96,284 3,956 (1,695)103,117 
Properties and equipment, net— 1,388,888 — — 1,388,888 
Operating lease right-of-use assets— 2,317 — — 2,317 
Net investment in leases— 539,705 101,871 (101,871)539,705 
Investment in subsidiaries2,432,767 69,754 — (2,502,521)— 
Intangible assets, net— 59,300 — — 59,300 
Goodwill— 342,762 — — 342,762 
Equity method investments— 235,858 34,746 — 270,604 
Deferred turnaround costs24,154 — — 24,154 
Other assets5,865 10,790 — — 16,655 
Total assets$2,443,204 $2,769,812 $140,573 $(2,606,087)$2,747,502 
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable$— $43,303 $545 $(1,339)$42,509 
Accrued interest17,992 — — — 17,992 
Deferred revenue— 12,087 — — 12,087 
Accrued property taxes— 5,449 — — 5,449 
Current operating lease liabilities— 968 — — 968 
Current finance lease liabilities— 6,560 — (2,171)4,389 
Other current liabilities117 1,793 520 — 2,430 
Total current liabilities18,109 70,160 1,065 (3,510)85,824 
Long-term debt1,556,334 — — — 1,556,334 
Noncurrent operating lease liabilities— 1,720 — — 1,720 
Noncurrent finance lease liabilities— 150,935 — (88,422)62,513 
Other long-term liabilities— 29,111 — — 29,111 
Deferred revenue— 24,613 — — 24,613 
Class B unit— 60,507 — — 60,507 
Equity - partners868,760 2,432,767 69,754 (2,514,155)857,126 
Equity - noncontrolling interests— 69,754 — 69,754 
Total liabilities and partners’ equity$2,443,203 $2,769,813 $140,573 $(2,606,087)$2,747,502 


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




Condensed Consolidating Balance Sheet
December 31, 2021ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
ASSETS
Current assets:
Cash and cash equivalents$1,273 $4,227 $8,881 $— $14,381 
Accounts receivable— 68,768 2,833 (2,702)68,899 
Prepaid and other current assets353 10,680 304 (304)11,033 
Total current assets1,626 83,675 12,018 (3,006)94,313 
Properties and equipment, net— 1,329,028 — — 1,329,028 
Operating lease right-of-use assets— 2,275 — — 2,275 
Net investment in leases— 309,301 100,032 (100,030)309,303 
Investment in subsidiaries1,785,024 70,437 — (1,855,461)— 
Intangible assets, net— 73,307 — — 73,307 
Goodwill— 223,650 — — 223,650 
Equity method investments— 78,873 37,505 — 116,378 
Deferred turnaround costs— 2,632 — — 2,632 
Other assets8,118 6,863 — — 14,981 
Total assets$1,794,768 $2,180,041 $149,555 $(1,958,497)$2,165,867 
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable$— $34,566 $8,416 $(2,702)$40,280 
Accrued interest11,258 — — — 11,258 
Deferred revenue— 14,585 — — 14,585 
Accrued property taxes— 4,542 — — 4,542 
Current operating lease liabilities— 620 — — 620 
Current finance lease liabilities— 5,566 — (1,780)3,786 
Other current liabilities3 1,513 265 — 1,781 
Total current liabilities11,261 61,392 8,681 (4,482)76,852 
Long-term debt1,333,049 — — — 1,333,049 
Noncurrent operating lease liabilities— 2,030 — — 2,030 
Noncurrent finance lease liabilities— 156,102 — (91,453)64,649 
Other long-term liabilities340 12,187 — — 12,527 
Deferred revenue— 29,662 — — 29,662 
Class B unit— 56,549 — — 56,549 
Equity - partners450,118 1,785,024 70,437 (1,862,562)443,017 
Equity - noncontrolling interests— 77,095 70,437 — 147,532 
Total liabilities and partners’ equity$1,794,768 $2,180,041 $149,555 $(1,958,497)$2,165,867 


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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) —
Intangible assets, 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 PARTNERS’ 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 partners’ equity $1,086,746
 $1,783,870
 $380,502
 $(1,366,881) $1,884,237















Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2022ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $438,280 $— $— $438,280 
Third parties— 109,200 — — 109,200 
— 547,480 — — 547,480 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 206,945 3,678 — 210,623 
Depreciation and amortization— 99,092 — — 99,092 
General and administrative3,777 13,226 — — 17,003 
3,777 319,263 3,678 — 326,718 
Operating income (loss)(3,777)228,217 (3,678)— 220,762 
Equity in earnings of subsidiaries299,319 8,071 — (307,390)— 
Equity in earnings of equity method investments— (3,585)3,325 — (260)
Interest expense(78,759)(20,296)— 16,495 (82,560)
Interest income— 91,406 16,495 (16,495)91,406 
Gain on sale of assets and other— 668 — — 668 
220,560 76,264 19,820 (307,390)9,254 
Income (loss) before income taxes216,783 304,481 16,142 (307,390)230,016 
State income tax expense— (111)— — (111)
Net income (loss)216,783 304,370 16,142 (307,390)229,905 
Allocation of net income attributable to noncontrolling interests— (5,051)(8,071)— (13,122)
Net income (loss) attributable to the Partnership216,783 299,319 8,071 (307,390)216,783 


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Year Ended December 31, 2017 Parent 
Guarantor
Restricted Subsidiaries
 Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
  (In thousands)
Revenues:          
Affiliates $—
 $351,395
 $25,741
 $—
 $377,136
Third parties —
 55,400
 21,826
 —
 77,226
  —
 406,795
 47,567
 —
 454,362
Operating costs and expenses:          
Operations (exclusive of depreciation and amortization) —
 122,619
 14,986
 —
 137,605
Depreciation and amortization —
 62,889
 16,389
 —
 79,278
General and administrative 4,170
 10,153
 —
 —
 14,323
  4,170
 195,661
 31,375
 —
 231,206
Operating income (loss) (4,170) 211,134
 16,192
 —
 223,156
Equity in earnings of subsidiaries 254,695
 12,148
 —
 (266,843) —
Equity in earnings of equity method investments —
 12,510
 —
 —
 12,510
Interest income —
 491
 —
 —
 491
Interest expense (43,260) (15,188) —
 —
 (58,448)
Loss on early extinguishment of debt (12,225) —
 —
 —
 (12,225)
Remeasurement gain on preexisting equity interests —
 36,254
 —
 —
 36,254
Gain on sale of assets and other —
 417
 5
 —
 422
  199,210
 46,632
 5
 (266,843) (20,996)
Income (loss) before income taxes 195,040
 257,766
 16,197
 (266,843) 202,160
State income tax expense —
 (249) —
 —
 (249)
Net income (loss) 195,040
 257,517
 16,197
 (266,843) 201,911
Allocation of net loss applicable to Predecessor —
 —
 —
 —
 —
Allocation of net income attributable to noncontrolling interests —
 (2,822) (4,049) —
 (6,871)
Net income (loss) attributable to the Partnership 195,040
 254,695
 12,148
 (266,843) 195,040
Other comprehensive income (loss) (91) (91) —
 91
 (91)
Comprehensive income (loss) attributable to the Partnership $194,949
 $254,604
 $12,148
 $(266,752) $194,949


Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2021ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $390,849 $— $— $390,849 
Third parties— 103,646 — — 103,646 
— 494,495 — — 494,495 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 167,832 2,692 — 170,524 
Depreciation and amortization— 93,800 — — 93,800 
General and administrative3,647 8,990 — — 12,637 
Goodwill Impairment— 11,034 — — 11,034 
3,647 281,656 2,692 — 287,995 
Operating income (loss)(3,647)212,839 (2,692)— 206,500 
Equity in earnings of subsidiaries275,558 2,532 — (278,090)— 
Equity in earnings of equity method investments— 8,897 3,535 — 12,432 
Interest income— 29,925 4,220 (4,220)29,925 
Interest expense(49,864)(8,174)— 4,220 (53,818)
Gain on sales-type lease— 31,778 — (7,101)24,677 
Gain on sale of assets and other— 6,179 — — 6,179 
225,694 71,137 7,755 (285,191)19,395 
Income (loss) before income taxes222,047 283,976 5,063 (285,191)225,895 
State income tax expense— (32)— — (32)
Net income (loss)222,047 283,944 5,063 (285,191)225,863 
Allocation of net income attributable to noncontrolling interests— (8,386)(2,531)— (10,917)
Net income (loss) attributable to the Partnership222,047 275,558 2,532 (285,191)214,946 




- 110 -

Year Ended December 31, 2016 Parent 
Guarantor
Restricted Subsidiaries
 Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
  (In thousands)
Revenues:          
Affiliates $—
 $307,049
 $26,067
 $—
 $333,116
Third parties —
 47,326
 21,601
 —
 68,927
  —
 354,375
 47,668
 —
 402,043
Operating costs and expenses:          
Operations (exclusive of depreciation and amortization) —
 111,181
 12,805
 —
 123,986
Depreciation and amortization —
 55,083
 15,345
 —
 70,428
General and administrative 3,804
 8,728
 —
 —
 12,532
  3,804
 174,992
 28,150
 —
 206,946
Operating income (loss) (3,804) 179,383
 19,518
 —
 195,097
Equity in earnings of subsidiaries 193,432
 14,634
 —
 (208,066) —
Equity in earnings of equity method investments —
 14,213
 —
 —
 14,213
Interest income —
 421
 19
 —
 440
Interest expense (31,387) (21,165) —
 —
 (52,552)
Gain on sale of assets and other —
 702
 (25) —
 677
  162,045
 8,805
 (6) (208,066) (37,222)
Income (loss) before income taxes 158,241
 188,188
 19,512
 (208,066) 157,875
State income tax expense —
 (285) —
 —
 (285)
Net income (loss) 158,241
 187,903
 19,512
 (208,066) 157,590
Allocation of net loss applicable to Predecessor —
 10,657
 —
 —
 10,657
Allocation of net income attributable to noncontrolling interests —
 (5,128) (4,878) —
 (10,006)
Net income (loss) attributable to the Partnership 158,241
 193,432
 14,634
 (208,066) 158,241
Other comprehensive income (loss) (99) (99) —
 99
 (99)
Comprehensive income (loss) attributable to the Partnership $158,142
 $193,333
 $14,634
 $(207,967) $158,142





Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2020ParentGuarantor
Restricted Subsidiaries		Non-Guarantor Non-Restricted SubsidiariesEliminationsConsolidated
 (In thousands)
Revenues:
Affiliates$— $399,809 $— $— $399,809 
Third parties— 98,039 — — 98,039 
— 497,848 — — 497,848 
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)— 146,585 1,107 — 147,692 
Depreciation and amortization— 99,578 — — 99,578 
General and administrative3,227 6,762 — — 9,989 
Goodwill Impairment— 35,653 — — 35,653 
3,227 288,578 1,107 — 292,912 
Operating income (loss)(3,227)209,270 (1,107)— 204,936 
Equity in earnings (loss) of subsidiaries254,608 219 — (254,827)— 
Equity in earnings of equity method investments— 5,105 1,542 — 6,647 
Interest income26 10,592 3 — 10,621 
Interest expense(55,298)(4,126)— — (59,424)
Gain on sales-type lease— 33,834 — — 33,834 
Loss on extinguishment of debt(25,915)— — — (25,915)
Gain on sale of assets and other289 8,402 — — 8,691 
173,710 54,026 1,545 (254,827)(25,546)
Income (loss) before income taxes170,483 263,296 438 (254,827)179,390 
State income tax expense— (167)— — (167)
Net income (loss)170,483 263,129 438 (254,827)179,223 
Allocation of net income attributable to noncontrolling interests— (8,521)(219)— (8,740)
Net income (loss) attributable to the Partnership170,483 254,608 219 (254,827)170,483 




- 111 -
Year Ended December 31, 2015 Parent 
Guarantor
Restricted Subsidiaries
 Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
  (In thousands)
Revenues:          
Affiliates $—
 $269,277
 $22,944
 $—
 $292,221
Third parties —
 47,189
 19,465
 —
 66,654
  —
 316,466
 42,409
 —
 358,875
Operating costs and expenses:          
Operations (exclusive of depreciation and amortization) —
 94,087
 11,469
 —
 105,556
Depreciation and amortization —
 48,302
 15,004
 —
 63,306
General and administrative 3,616
 8,940
 —
 —
 12,556
  3,616
 151,329
 26,473
 —
 181,418
Operating income (loss) (3,616) 165,137
 15,936
 —
 177,457
Equity in earnings (loss) of subsidiaries 161,097
 11,915
 —
 (173,012) —
Equity in earnings of equity method investments —
 4,803
 —
 —
 4,803
Interest income —
 526
 —
 —
 526
Interest expense (20,273) (17,145) —
 —
 (37,418)
Gain on sale of assets and other —
 535
 (49) —
 486
  140,824
 634
 (49) (173,012) (31,603)
Income (loss) before income taxes 137,208
 165,771
 15,887
 (173,012) 145,854
State income tax expense —
 (228) —
 —
 (228)
Net income (loss) 137,208
 165,543
 15,887
 (173,012) 145,626
Allocation of net loss applicable to Predecessors —
 2,702
 —
 —
 2,702
Allocation of net income attributable to noncontrolling interests —
 (7,148) (3,972) —
 (11,120)
Net income (loss) attributable to the Partnership 137,208
 161,097
 11,915
 (173,012) 137,208
Other comprehensive income (loss) 236
 236
 —
 (236) 236
Comprehensive income (loss) attributable to the Partnership $137,444
 $161,333
 $11,915
 $(173,248) $137,444


Note 18: Osage Pipeline



On July 8, 2022, the Osage pipeline, which is owned by Osage (see Note 1) and carries crude oil from Cushing, Oklahoma to El Dorado, Kansas, suffered a release of crude oil. Our equity in earnings of equity method investments was reduced in the year ended December 31, 2022 by $17.6 million for our 50% share of incurred and estimated environmental remediation and recovery expenses associated with the release, net of our share of insurance proceeds received to date of $3.0 million. Any additional insurance recoveries will be recorded as they are received. If our insurance policy pays out in full, our share of the remaining insurance coverage is expected to be $9.5 million. As Osage is an equity method investment, its financial position and results are not consolidated into HEP financial statement line items. The financial impact of the Osage crude oil release is reflected on the consolidated balance sheets as a reduction in equity method investments and is reflected on the consolidated statement of income as a reduction in equity in earnings (loss) of equity method investments.
Condensed Consolidating Statement
The pipeline resumed operations in the third quarter of Cash Flows2022 and remediation efforts are underway. It may be necessary for Osage to accrue additional amounts for environmental remediation or other release-related expenses in future periods, but we cannot estimate those amounts at this time. Future costs and accruals could have a material impact on our results of operations and cash flows in the period recorded; however, we do not expect them to have a material impact on our financial position.

- 112 -
Year Ended December 31, 2017 Parent 
Guarantor
Restricted Subsidiaries
 Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
  (In thousands)
Cash flows from operating activities $(51,235) $268,978
 $32,892
 $(12,148) $238,487
           
Cash flows from investing activities          
Additions to properties and equipment —
 (41,827) (2,983) —
 (44,810)
Purchase of controlling interests in SLC Pipeline and Frontier Aspen —
 (245,446) —
 —
 (245,446)
Proceeds from the sale of assets —
 849
 —
 —
 849
Distributions in excess of equity in earnings of equity method investments —
 3,134
 —
 —
 3,134
Distributions from UNEV in excess of earnings —
 7,352
 —
 (7,352) —
  —
 (275,938) (2,983) (7,352) (286,273)
Cash flows from financing activities          
Net repayments under credit agreement 1,012,000
 (553,000) —
 —
 459,000
Net intercompany financing activities (561,675) 561,675
 —
 —
 —
Redemption of notes (309,750) —
 —
 —
 (309,750)
Proceeds from issuance of 6% Senior Notes 101,750
 —
 —
 —
 101,750
Proceeds from issuance of common units 52,100
 10
 —
 —
 52,110
Contributions from general partner 1,440
 (368) —
 —
 1,072
Distributions to HEP unitholders (234,575) —
 —
 —
 (234,575)
Distributions to noncontrolling interest —
 —
 (26,000) 19,500
 (6,500)
Contributions to HFC for El Dorado Operating Tanks (103) —
 —
 —
 (103)
Deferred financing costs (9,347) (35) —
 —
 (9,382)
Units withheld for tax withholding obligations (605) —
 —
 —
 (605)
Other —
 (1,112) —
 —
 (1,112)
  51,235
 7,170
 (26,000) 19,500
 51,905
Cash and cash equivalents          
Increase for the period —
 210
 3,909
 —
 4,119
Beginning of period 2
 301
 3,354
 —
 3,657
End of period $2
 $511
 $7,263
 $—
 $7,776








Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2016 Parent 
Guarantor
Restricted Subsidiaries
 Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
  (In thousands)
Cash flows from operating activities $(19,641) $245,771
 $32,052
 $(14,634) $243,548
           
Cash flows from investing activities          
Additions to properties and equipment —
 (44,447) (15,257) —
 (59,704)
Acquisition of tanks and refinery processing units —
 (44,119) —
 —
 (44,119)
Purchase of interest in Cheyenne Pipeline —
 (42,627) —
 —
 (42,627)
Proceeds from sale of assets —
 427
 —
 —
 427
Distributions from UNEV in excess of earnings —
 2,616
 —
 (2,616) —
Distribution in excess of equity in earnings in equity investments —
 2,993
 —
 —
 2,993
  —
 (125,157) (15,257) (2,616) (143,030)
           
Cash flows from financing activities          
Net borrowings under credit agreement —
 (159,000) —
 —
 (159,000)
Net intercompany financing activities (302,600) 302,600
 —
 —
 —
Proceeds from issuance of 6% Senior Notes 394,000
 —
 —
 —
 394,000
Proceeds from issuance of common units 125,870
 —
 —
 —
 125,870
Contributions from General partner 2,577
 —
 —
 —
 2,577
   Distributions to noncontrolling interests —
 —
 (23,000) 17,250
 (5,750)
Distributions to HEP unitholders (192,037) —
 —
 —
 (192,037)
Distributions to HFC for acquisitions (30,378) (287,122) —
 —
 (317,500)
Contributions from HFC for acquisitions (3,397) 54,659
 —
 —
 51,262
Distributions to HFC for acquisitions 31,287
 (31,287) —
 —
 —
Distribution to HFC for Osage acquisition —
 (1,245) —
 —
 (1,245)
Deferred financing costs (910) (3,085) —
 —
 (3,995)
Purchase of units for incentive grants (3,521) —
 —
 —
 (3,521)
Units withheld for tax withholding obligations (800) —
 —
 —
 (800)
Other (450) (1,285) —
 —
 (1,735)
  19,641
 (125,765) (23,000) 17,250
 (111,874)
Cash and cash equivalents          
Increase (decrease) for the period —
 (5,151) (6,205) —
 (11,356)
Beginning of period 2
 5,452
 9,559
 —
 15,013
End of period $2
 $301
 $3,354
 $—
 $3,657







Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2015 Parent 
Guarantor
Restricted Subsidiaries
 Non-Guarantor Non-Restricted Subsidiaries Eliminations Consolidated
  (In thousands)
Cash flows from operating activities $(18,794) $232,650
 $29,501
 $(11,915) $231,442
           
Cash flows from investing activities          
Additions to properties and equipment —
 (37,951) (1,442) —
 (39,393)
Acquisition of tanks and operating units —
 (153,728) —
 —
 (153,728)
Purchase of investment in Frontier Pipeline —
 (55,032) —
 —
 (55,032)
Proceeds from sale of assets —
 1,279
 —
 —
 1,279
Distributions from UNEV in excess of earnings —
 1,960
 —
 (1,960) —
Distributions in excess of equity in earnings in equity investments —
 194
 —
 —
 194
  —
 (243,278) (1,442) (1,960) (246,680)
           
Cash flows from financing activities          
Net borrowings under credit agreement —
 141,000
 —
 —
 141,000
Net intercompany financing activities 192,108
 (192,108) —
 —
 —
Distributions to noncontrolling interests —
 —
 (18,500) 13,875
 (4,625)
Distributions to HEP unitholders (169,063) —
 —
 —
 (169,063)
Contributions from HFC for acquisitions —
 128,476
 —
 —
 128,476
Distributions to HFC for acquisitions —
 (62,000) —
 —
 (62,000)
Purchase of units for incentive grants (3,555) —
 —
 —
 (3,555)
Deferred financing costs —
 (962) —
 —
 (962)
Units withheld for tax withholding obligations (696) —
 —
 —
 (696)
Other —
 (1,154) —
 —
 (1,154)
  18,794
 13,252
 (18,500) 13,875
 27,421
Cash and cash equivalents          
Increase for the period —
 2,624
 9,559
 —
 12,183
Beginning of period 2
 2,828
 —
 —
 2,830
End of period $2
 $5,452
 $9,559
 $—
 $15,013





Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We have had no change in, or disagreement with, our independent registered public accounting firm on matters involving accounting and financial disclosure.




Item 9A.Controls and Procedures
Item 9A.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 annual report on Form 10-K. 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, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2017,2022, at a reasonable level of assurance.
(b) Changes in internal control over financial reporting
We acquired additional equity interests in SLC Pipeline and Frontier Aspen from Plains effective October 31, 2017, and we accounted for their acquisition as a business combination achieved in stages. We have included SLC Pipeline and Frontier Aspen’s operating results, assets and liabilities in our consolidated financial statements as of December 31, 2017, and for the two months then ended. Pursuant to a Transition Service Agreement with Plains, Plains provides certain accounting support services for SLC Pipeline and Frontier Aspen. Other than internal controls for SLC Pipeline and Frontier Aspen, thereThere 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.
See Item 8 for “Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”




Item 9B.Other Information
Item 9B.Other Information
There have been no events that occurred in the fourth quarter of 20172022 that would need to be reported on Form 8-K that have not been previously reported.





Item 9C.    Disclosure Regarding Foreign Jurisdictions that Prevent Inspections


Not applicable

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A
PART III


- 114 -

A

Item 10. Directors, Executive Officers and Corporate Governance


Holly Logistic Services, L.L.C. (“HLS”), the general partner of HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, manages our operations and activities. Neither our general partner nor our directors are elected by our unitholders. Unitholders are not entitled to directly or indirectly participate in our management or operations. The sole member of HLS, which is a subsidiary of HFC,HF Sinclair, appoints the directors of HLS to serve until their death, resignation or removal.


Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.


Executive Officers


The following sets forth information regarding the executive officers of HLS as of February 14, 2018:15, 2023:


NameAgePosition with HLS
George J. DamirisMichael C. Jennings57Chief Executive Officer and President
Richard L. Voliva IIIJohn Harrison4044ExecutiveSenior Vice President, Chief Financial Officer and Treasurer
Robert I. Jamieson58Senior Vice President and Chief FinancialOperating Officer
Mark T. CunninghamVaishali S. Bhatia5840Senior Vice President, Operations and Engineering
Denise C. McWatters58Senior Vice President, General Counsel and Secretary


During 2017,On January 13, 2023, the Board of Directors of HLS (the “Board”) appointed Robert I. Jamieson as Senior Vice President and Chief Operating Officer of HLS effective January 18, 2023. Mr. Cunningham wasJamieson is the only HLS executive officer listed above who spentspends all of his professional time managing our business and affairs. The other executive officers listed above are also executive officers of HFCHF Sinclair and devote as much of their professional time as is necessary to oversee the management of our business and affairs.


Information regarding Mr. DamirisJennings is included below under “Directors.”


Richard L. Voliva III was appointedJohn Harrison has served as ExecutiveSenior Vice President, Chief Financial Officer and Treasurer of HLS since January 2020. Mr. Harrison previously served as Vice President, Finance, Investor Relations and Treasurer of HLS from October 2018 to January 2020. He has served as Vice President, Finance, Strategy and Treasurer of HF Sinclair since September 2020. Mr. Harrison previously served as Vice President, Finance, Investor Relations and Treasurer of HFC from September 2018 to September 2020. He previously served as Vice President and Chief Financial OfficerTreasurer of HLS and HFC from January 2017 to October 2018, Business Development Representative of HLS and HFC from April 2013 to December 2016, Assistant Treasurer of HLS and HFC from August 2012 to March 2013, Manager, Credit & Collections of HLS and HFC from March 2010 to August 2012, Supervisor, Credit & Collections of HLS and HFC from January 2007 to February 2010 and Financial Analyst of HLS and HFC from October 2005 to February 2007. Prior to joining Holly Corporation, Mr. Harrison worked in March 2017. Hethe Planning & Financial Management group at JPMorgan Chase & Co.

Robert I. Jamieson has also served as Executive Vice President and Chief Financial Officer of HFC since March 2017. Mr. Voliva served as Senior Vice President and Chief FinancialOperating Officer of HLS from July 2016 to March 2017,since January 2023.Mr. Jamieson previously served as Vice President, and Chief Financial OfficerPipeline Operations of HLS from October 2015 until July 2016, Vice President, Corporate Development of HLS from February 2015 until October 2015 and Senior Director, Business Development of HLS from April 2014 until February 2015. Mr. Voliva also served as Senior Vice President, Strategy for HFC from June 2016March 2013 to March 2017.January 2023. Prior to joining HLS, Mr. Voliva was an analyst at Millennium Management LLC, an institutional asset manager, from April 2011 until April 2014, an analyst at Partner Fund Management, L.P., a hedge fund, from March 2008 until March 2011he held various roles of increasing responsibility in engineering and Vice President, Equity Research at Deutsche Bank from June 2005 to March 2008. Mr. Voliva is a CFA Charterholder.

Mark T. Cunningham was appointed Senior Vice President, Operations and Engineering in January 2018. He previously served as Senior Vice President, Engineering and Technical Services from July 2016 to January 2018, Senior Vice President, Operations from January 2013 to July 2016 and Vice President, Operations from July 2007 to January 2013. He served Holly Corporation as Senior Manager of Special Projects from December 2006 through June 2007 and as Senior Manager of Integrity Management and Environmental, Health and Safety from July 2004 through December 2006. Prior to joining Holly Corporation, Mr. Cunningham served Diamond Shamrock/Ultramar Diamond Shamrock for 20 years in several engineeringplant and pipeline operations capacities.over a 25 year period at Eagle Rock Energy Partners, L.P., Enterprise Products Partners L.P., Williams Energy Partners LP (now known as Magellan Midstream Partners, L.P.), and TC Energy Corporation (formerly known as TransCanada Corporation).


Denise C. McWatters was appointedVaishali S. Bhatia has served as Senior Vice President, General Counsel and Secretary in January 2013.  Ms. McWatters also serves in a similar capacity for HFC. Ms. McWatters previouslyof HLS since November 2019. She served as Vice President,Chief Compliance Officer of HLS from August 2019 to January 2020, Acting General Counsel and Secretary of HLS from April 2008 until January 2013. She joined Holly Corporation in October 2007 with more than 20 years of legal experience and served as DeputyAugust 2019 to November 2019, Assistant General Counsel of Holly Corporation until April 2008HLS from May 2017 to August 2019, Assistant Secretary of HLS from January 2013 to August 2019 and Counsel of HLS from October 2011 to May 2017. Ms. Bhatia has also served as Senior Vice President, General Counsel and Secretary of HFC (formerly Holly Corporation) from April 2008 until January 2013.  Ms. McWattersHF Sinclair since November 2019. She served as theChief Compliance Officer of HFC from August 2019 to January 2020, Acting General Counsel and Secretary of HFC from August 2019 to November 2019, Assistant General Counsel of The Beck GroupHFC from 2005 through 2007.May 2017 to August 2019, Assistant Secretary of HFC from May 2012 to August 2019 and Counsel of HFC from October 2011 to May 2017. Prior to joining The Beck Group,HFC, Ms. McWatters practiced law in various capacitiesBhatia was an associate at the predecessor firm to Locke Lord Bissell & Liddell LLP, the Law Offices of Denise McWatters, the legal department at Citigroup, N.A., and the law firm of Cox Smith Matthews Incorporated.Jones Day.



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A
Board Leadership Structure


The Board of Directors of HLS (the “Board”) is responsible for selecting the Board leadership structure that is in the best interest of HLS and HEP. At this time,Currently, Mr. Jennings serves as Chairperson of the Board and as the Chief Executive Officer and President of HLS. Independent directors and management have different perspectives and roles in strategy development. The independent directors on the Board bring experience, oversight and expertise from outside HLS, HEP and the industry, while the Chief Executive Officer brings HLS and HEP experience and expertise. The Board believes that separating the positionscombined role of ChairmanChairperson of the Board and Chief Executive Officer working with the lead independent director (the “Presiding Director”), is in the best interest of HLS and HEP. Currently, Mr. Michael C. Jennings serves as Chairman of the Board in a non-employee capacity, and Mr. Damiris serves as the Chief Executive Officer of HLS. The Board believes thatunitholders at this time because the separation of these positions enhances thecombined role for HLS provides balance between strategy development and independent oversight of management, by the Board andboth of which are particularly useful in HLS’s and HEP’s overall leadership structure. In addition, as a result of his former role as HFC’s and HLS’s Chief Executive Officer, Mr. Jennings has company-specific experience and expertise and as Chairman of the Board can identify strategic priorities, lead the discussion and execution of strategy, and facilitate the flow of information between management and the Board.general partner.


ChairmanChairperson of the Board


Mr. Jennings was selected by the directors of HLS to serve as the ChairmanChairperson of the Board. The ChairmanChairperson has the following responsibilities:


•designating and calling meetings of the Board;


•presiding at all Board meetings;


•consulting with management on Board and committee meeting agendas;


•facilitating teamwork and communication between the Board and management; and


•acting as a liaison between management and the Board.


Since Mr. Jennings is notPresiding Director
Larry R. Baldwin, an employeeindependent director, was appointed by the non-employee directors of HLS or HEP, he also presidesto serve as the Presiding Director of the Board. The Presiding Director has the following responsibilities:

•presiding at all executive sessions of the non-employee directors of the Board.Board;


•consulting with management on Board and committee meeting agendas;

•facilitating teamwork and communication between the non-employee directors and management; and

•acting as a liaison in appropriate instances between management and the non-employee directors, including advising the Chairperson of the Board and Chief Executive Officer on the efficiency of the Board meetings

Persons wishing to communicate with the non-employee directors are invited to email the ChairmanPresiding Director at presiding.director.HEP@hollyenergy.com or write to: Michael C. Jennings, Chairman,Larry R. Baldwin, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Communications to the Board generally may be sent by certified mail to Holly Logistic Services, L.L.C., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507, Attention: Secretary. The Secretary will forward all communication to the appropriate director or directors, other than those communications that are merely solicitations for products or services or relate to matters that are of a type that are clearly improper or irrelevant to the functioning of the Board or the business and affairs of HLS and HEP.
Risk Management


The Board has an active role in overseeing management of the risks affecting HLS and HEP. The Board regularly reviews information regarding HLS and HEP’s credit, liquidity, business, operations and business and operations,cybersecurity, as well as the risks associated with each. The Board committees are also engaged in overseeing risk associated with HLS and HEP.


•The Compensation Committee oversees the management of risks relating to HLS’s executive compensation plans and arrangements.


•The Audit Committee oversees management of financial reporting and controls risks.


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•The Conflicts Committee oversees specific matters that the Boardit or the Conflicts CommitteeBoard believes may involve conflicts of interest with HFC.HF Sinclair.


While each committee is responsible for evaluating certain risks and overseeing the management of such risks, the entire Board is ultimately responsible for the risk management of HLS and HEP and is regularly informed on these matters through committee reports about such risks.and senior management presentations.


The sole member of HLS manages risks associated with the independence of the Board. The Audit Committee and the Board also receivereceives input and reports from HLS’s risk management oversight committee on management’s views of the risks facing HLS and HEP. The risk management oversight committee is made up of management personnel, none of whom serve on the Board and all of whom have a range of different backgrounds, skills and experiences with regard to the operational, financial and strategic risk


profile of HLS and HEP. The risk management oversight committee monitorssupports the efforts of the Board and the Board committees to monitor and evaluate guidelines and policies governing HLS’s and HEP’s risk environment for HLSassessment and HEP as a whole, and reviews the activities that mitigate risks to an achievable and acceptable level.management.


Director Qualifications


The Board believes that it is necessary for each of HLS’s directors to possess a varietyrange of qualitiesrelevant skills, expertise, knowledge and skills.diversity of opinion. When searching for new candidates, the sole member of HLS considers the evolving needs of the Board and searches for candidates that fill any current or anticipated future needs. The Board also believes that all directors must possess a considerable amount of business management, business leadership and educational experience. When consideringIn evaluating the suitability of individual director candidates, the sole member of HLS first considers a candidate’s management experience and then considers issues of judgment, background, stature, conflicts of interest, integrity, ethics, industry knowledge, ability to commit adequate time to the Board, and commitment to the goal of maximizing unitholder value. The sole member of HLS also focuses on issues of diversity, such asconsiders diversity of education, professionalrace, gender expression and identity, age, sexual orientation, ethnicity, knowledge, experience, viewpoints, geography, and differences in viewpoints and skills. The sole member of HLS does not have a formal policy with respect to diversity; however, the Board and the sole member of HLS believe that it is essential that the Board members represent diverse viewpoints. other demographics.In considering candidates for the Board, the sole member of HLS considers the entirety of each candidate’s credentials in the context of these standards. All our directors bring to the Board executive leadership experience derived from their service in many areas.


Pursuant to the Governance Guidelines of HLS and HEP, a director must submit his or her resignation to the Board inon the first quarter of the calendar year indate on which the director will attain the age of 75 or greater.If the resignation is accepted by the Board, the resignation will be effective on December 31 of the year in which the resignationno later than 12 months from when it was accepted by the Board. In the first quarter of 2016, Mr. Jerry W. Pinkerton submitted his resignation in accordance with the policy. His resignation was not accepted by the Board at that time. In the fourth quarter of 2016, the Board reconsidered his resignation, but decided to not accept his resignation at that time. In the first quarter of 2017, the Board again reconsidered his resignation and accepted his resignation effective June 30, 2017.submitted.

On February 7, 2018, the sole member of HLS appointed Christine B. LaFollette and Eric L. Mattson to the Board effective March 1, 2018. In addition, on February 7, 2018, Mr. R. Kevin Hardage notified the Board that he will resign from the Board effective February 28, 2018.


Director Independence


The Board has determined that Messrs. Larry R. Baldwin, R. Kevin Hardage andChristine B. LaFollette, James H. Lee and Eric L. Mattson meet the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange (“NYSE”). The Board previously determined that Matthew P. Clifton, Charles M. Darling IV, Jerry W. Pinkerton, William P. StengelMr. Jennings is not independent because he is an officer of HLS and James G. Townsend were “independent” as definedan employee of HF Sinclair. Mr. Petersen is not independent because he provided certain consulting services to HF Sinclair in 2022 pursuant to a consulting agreement he entered into with HF Sinclair on the closing of the Sinclair Transactions and received compensation for his services in the aggregate amount of $120,000.Mr. Petersen’s consulting agreement expired in October 2022 according to its terms and was approved by the NYSE listing standards during the time they served on the Board. Messrs. Clifton, Darling, Stengel and Townsend retired from the Board effective November 2017, and,Audit Committee as previously discussed, the Board accepted Mr. Pinkerton’s resignation pursuant to the Board retirement policy effective June 2017. The Board has also determined that Ms. LaFollette and Mr. Mattson meet the applicable criteria for independencea related party transaction under the current applicable rulesItem 404(a) of NYSE.Regulation S-K.


Audit Committee.The Audit Committee of HLS is currently composed of three directors, Messrs. Baldwin, HardageLee and Lee.Mattson. The Board has determined that each member of the Audit Committee is “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Securities Exchange Act of 1934 (the “Exchange Act”). The Board previously determined that Messrs. Clifton, Pinkerton and Darling were “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act during the time they served on the Audit Committee. Mr. Hardage notified the Board that he will resign from the Board on February 28, 2018. The Board has appointed Mr. Mattson to the Audit Committee effective March 1, 2018. The Board has determined that Mr. Mattson is “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act.

Conflicts Committee.The Conflicts Committee of HLS is currently composed of Mr. Baldwin.three directors, Messrs. Baldwin and Mattson and Ms. LaFollette. The Board has determined that heeach member of the Conflicts Committee is “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act, as required by the Conflicts Committee Charter. The Board previously determined that Messrs. Clifton, Stengel, Pinkerton and Townsend were “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act during the time they served on the Conflicts Committee. The Board has appointed Ms. LaFollette and Mr. Mattson to the Conflicts Committee effective March 1, 2018. The Board has determined that Ms. LaFollette and Mr. Mattson are “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act.


Compensation Committee.The Compensation Committee of HLS is currently composed of threefour directors, Messrs. Jennings, DamirisLee and Lee.Petersen and Ms. LaFollette. The Board has determined that Mr. Lee isand Ms. LaFollette are “independent” as defined by the NYSE listing standards.Because we are a master limited partnership, Rule 303A.05 of the NYSE Listed Company Manual, which requires a publicly traded company to have a compensation committee composed entirely of independent directors, does not apply to us. The Board



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previously determined that Messrs. Darling, Stengel and Townsend were “independent” as defined by the NYSE listing standards during the time they served on the Compensation Committee. The Board has appointed Ms. LaFollette to the Compensation Committee effective March 1, 2018. The Board has determined that Mr. LaFollette is “independent” as defined by the NYSE listing standards.

Independence Determinations. In making its independence determinations, the Board considered certain transactions, relationships and arrangements. In determining Mr. Townsend’s independence during the time he served on the Board, the Board considered that Mr. Townsend has not been employed by HFC or HLS since 2011 and has not received compensation in excess of $120,000 since 2011. In determining Mr. Clifton’s independence during the time he served on the Board, the Board considered that Mr. Clifton has not been employed by HFC or HLS since 2014 and has not received compensation in excess of $120,000 since 2013. In determining Ms. LaFollette’s independence, the Board considered that during fiscal year 2017, Akin Gump Strauss Hauer & Feld LLP served as outside counsel to the Conflicts Committee. Ms. LaFollette did not represent the Conflicts Committee of the Board on any matters, and Akin Gump Strauss Hauer & Feld LLP will no longer represent the Conflicts Committee of the Board in light of Ms. LaFollette’s appointment to the Board.

Code of Business Conduct and Ethics


HLS has adopted a Code of Business Conduct and Ethics (the “Code”) that applies to all of its officers, directors and employees, including HLS’s principal executive officer, principal financial officer, and principal accounting officer. The purpose of the Code of Business Conduct and Ethics is to, among other things, affirm HLS’s and HEP’s commitment to a high standard of integrity and ethics. The Code sets forth a common set of values and standards to which all of HLS’s officers, directors and employees must adhere. We will post information regarding an amendment to, or a waiver from, the Code of Business Conduct and Ethics on our website.


Copies of our Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and the Code of Business Conduct and Ethics are available on our website at www.hollyenergy.com. Copies of these documents may also be obtained free of charge upon written request to Holly Energy Partners, L.P., Attention: Director,Vice President, Investor Relations, 2828 N. Harwood, Suite 1300, Dallas, Texas, 75201-1507.


The Board, Its Committees and Director Compensation


Directors


The following individuals currently serve as directorsCurrently, the Board consists of HLS:six directors.



Michael C. Jennings     Director since October 2011. Age 52.57.


Principal Occupation
Principal Occupation:    Chief Executive Officer and President of HLS and Chief Executive Officer of HF Sinclair.

Business Experience:
Chairman of the Board of HLS and Chairman of the Board of HFC

Business Experience:
Mr. Jennings has served as Chairman of the Board of HLS since November 2017 and Chairman of the Board of HFC since January 2017, a position he previously held from January 2013 until January 2016.    Mr. Jennings has served as Chief Executive Officer of HLS since January 2020 and as President of HLS since September 2022. He has served as the Chairperson of the Board of HLS since November 2017. Mr. Jennings previously served as Chief Executive Officer of HLS from January 2014 to November 2016 and as President of HLS from October 2015 to February 2016. Mr. Jennings served as Executive Chairman of HFC from January 2016 until January 2017 and as the Chief Executive Officer and President of HFC from the merger of Holly Corporation and Frontier Oil Corporation in July 2011 until January 2016. Mr. Jennings previously served as the President and Chief Executive Officer of Frontier Oil Corporation from 2009 until the merger in July 2011 and as the Executive Vice President and Chief Financial Officer of Frontier Oil Corporation from 2005 until 2009.

Additional Directorships:Mr. Jennings currently serves as the Chairman and a director of HFC and a director of ION Geophysical Corporation. Mr. Jennings served as a director of Frontier Oil Corporation from 2008 until the merger in July 2011 and as Chairman of the board of directors of Frontier Oil Corporation from 2010 until the merger in July 2011.

Qualifications:
Mr. Jennings provides valuable and extensive industry knowledge and experience. His knowledge of the day-to-day operations of HFC provides a significant resource for the Board and facilitates discussions between the Board and HFC management.




George J. Damiris     Director since February 2016. Age 57.Mr. Jennings has served as Chief Executive Officer of HF Sinclair since January 2020. Mr. Jennings also served as President of HFC from January 2020 to November 2021, as Executive Vice President of HFC from November 2019 to January 2020, as Executive Chairman of HFC from January 2016 to January 2017 and as the Chief Executive Officer and President of HFC from the merger of Holly Corporation and Frontier Oil Corporation in July 2011 to January 2016. Mr. Jennings previously served as the President and Chief Executive Officer of Frontier Oil Corporation from 2009 until the merger in July 2011 and as the Executive Vice President and Chief Financial Officer of Frontier Oil Corporation from 2005 to 2009.


Principal Occupation:
Additional Directorships:    Mr. Jennings currently serves as a director of HF Sinclair. Mr. Jennings served as Chairperson of the Board of HFC from January 2017 to February 2019 and January 2013 to January 2016. Mr. Jennings served as a director of FTS International, Inc. from January 2019 to November 2020, as a director and Chairman of the Board of Montage Resources and its predecessor entities from May 2016 to November 2019, and as a director of ION Geophysical Corporation from December 2010 until February 2019. He served as a director of Frontier Oil Corporation from 2008 until the merger in July 2011 and as Chairman of the board of directors of Frontier Oil Corporation from 2010 until the merger in July 2011.

Qualifications:    Mr. Jennings provides valuable and extensive industry knowledge and experience. His knowledge of the day-to-day operations of HF Sinclair is a significant resource for the Board and facilitates discussions between the Board and HF Sinclair management.
Chief Executive Officer and President of HFC and Chief Executive Officer and President of HLS

Business Experience:
Mr. Damiris has served as the Chief Executive Officer of HLS since November 2016, as President of HLS since February 2017 and as Chief Executive Officer and President of HFC since January 2016. He previously served as Executive Vice President and Chief Operating Officer of HFC from September 2014 until January 2016 and as Senior Vice President, Supply and Marketing of HFC from January 2008 until September 2014. Mr. Damiris joined HFC in 2007 as Vice President, Corporate Development after an 18-year career with Koch Industries, where he was responsible for managing various refining, chemical, trading, and financial businesses.

Additional Directorships:Mr. Damiris currently serves as a director of Eagle Materials Inc. and of HFC.

Qualifications:
Mr. Damiris has extensive industry experience and significant insight into issues facing the industry. His knowledge of the day-to-day operations of HFC provides a significant resource for the Board and facilitates discussions between the Board and HFC management.



Larry R. Baldwin    Director since May 2016. Age 65.70.


Principal Occupation:    Former Partner at Deloitte LLP.


Business Experience:
Business Experience:    Mr. Baldwin was employed for 41 years as an auditor by Deloitte LLP and predecessor firms, including 31 years as a partner, prior to retiring from such position in May 2015. While he was a partner at Deloitte LLP, Mr. Baldwin held a number of practice management positions.

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Qualifications:    Mr. Baldwin brings to the Board his audit, accounting and financial reporting expertise, which also qualify him as an audit committee financial expert. Due to his audit and practice management experience with Deloitte LLP, Mr. Baldwin possesses business, industry and management expertise that provide valuable insight to the Board and the management of HEP.
Mr. Baldwin was employed for 41 years as an auditor by Deloitte LLP and predecessor firms, including 31 years as a partner, prior to retiring from such position in May 2015. While he was a partner at Deloitte LLP, Mr. Baldwin held a number of practice management positions.

Qualifications:
Mr. Baldwin brings to the Board his audit, accounting and financial reporting expertise, which also qualify him as an audit committee financial expert. Due to his audit and practice management experience with Deloitte LLP, Mr. Baldwin possesses business, industry and management expertise that provide valuable insight to the Board and the management of the Company.



R. Kevin HardageChristine B. LaFollette     Director since March 2018. Age 70.

Principal Occupation:    Partner Emeritus at Akin Gump Strauss Hauer & Feld LLP.

Business Experience:    Ms. LaFollette served as Partner at Akin Gump Strauss Hauer & Feld LLP from June 2004 until her retirement in December 2020. Beginning in January 2021, Ms. LaFollette was named Partner Emeritus at Akin Gump Strauss Hauer & Feld LLP. Prior to that, Ms. LaFollette served as a Partner at King & Spalding LLP from 1997 to June 2004, as a Partner at Andrews & Kurth LLP from 1987 to 1997 and as an associate at Andrews & Kurth LLP from 1980 to 1987.

Qualifications:    Ms. LaFollette’s experience as a transactional and securities attorney provides her with valuable insight into corporate finance, global compliance, and governance matters. In addition, Ms. LaFollette brings to the Board a broad range of experiences and skills as a result of her involvement in numerous charitable, community and civic activities.
_____________________________________________________________________________________________    

James H. Lee         Director since November 2017. Age 56.74.

Principal Occupation:
Chief Executive Officer of Turtle Creek Trust Company, Co-founder, President and Portfolio Manager of Turtle Creek Management, LLC and a non-controlling manager and member of TCTC Holdings, LLC

Business Experience:
Mr. Hardage has served as Chief Executive Officer of Turtle Creek Trust Company, a private trust and investment management firm, since 2009 and has served as President and Portfolio Manager of Turtle Creek Management, a registered investment advisory firm, since 2006. In addition, Mr. Hardage serves as a non-controlling manager and member of TCTC Holdings, LLC, a bank holding company that is a banking, securities and investment management firm.

Additional Directorships:Mr. Hardage currently serves as a director of HFC.

Qualifications:
Mr. Hardage brings to the Board executive and general management experience as well as significant financial expertise.
_____________________________________________________________________________________________    

Principal Occupation:    Managing General Partner and Principal Owner of Lee, Hite & Wisda Ltd.
James H.
Business Experience:    Mr. Lee         Director has served as the Managing General Partner of Lee, Hite & Wisda Ltd., a private company with investments in oil and gas working, royalty and mineral interests, since November 2017. Age 69.founding the firm in 1984.

Principal Occupation:
Managing General Partner and Principal Owner of Lee, Hite & Wisda Ltd.

Business Experience:
Mr. Lee has served as the Managing General Partner of Lee, Hite & Wisda Ltd., a private company with investments in oil and gas working, royalty and mineral interests, since founding the firm in 1984.



Additional Directorships:    Mr. Lee currently serves as a director of HF Sinclair. He served as a director of Frontier Oil Corporation from 2000 until July 2011.


Additional Directorships:Mr. Lee currently serves as a director of HFC. He served as a director of Frontier Oil Corporation from 2000 until July 2011 and as a director of Forest Oil Corporation from 1991 until December 2014.

Qualifications:
Qualifications:    Mr. Lee brings to the Board his extensive experience as a consultant and investor in the oil and gas industry, which provides him with significant insights into relevant industry issues.


The following directors are appointed to the Board effectivehis extensive experience as a consultant and investor in the oil and gas industry, which provides him with significant insights into relevant industry issues.


Eric L. Mattson         Director since March 1, 2018:

Christine B. LaFollette     Director effective March 1, 2018. Age 65.71.


Principal Occupation:
Principal Occupation:    Former Executive Vice President, Finance of Select Energy Services, Inc.

Business Experience:    Mr. Mattson served as Executive Vice President, Finance of Select Energy Services, Inc., a provider of total water solutions to the U.S. unconventional oil and gas industry, from November 2016 until his retirement in March 2018 and served as Executive Vice President and Chief Financial Officer of Select Energy Services, Inc. from November 2008 through January 2016.Prior to that, Mr. Mattson served as Senior Vice President and Chief Financial Officer of VeriCenter, Inc., a private provider of managed hosting services, from 2003 until its acquisition in August 2007.Mr. Mattson worked as an independent consultant from November 2002 to October 2003.Mr. Mattson served as the Chief Financial Officer of Netrail, Inc., a private Internet backbone and broadband service provider, from September 1999 until November 2002.From July 1993 until May 1999, Mr. Mattson served as Senior Vice President and Chief Financial Officer of Baker Hughes Incorporated, a provider of products and services to the oil, gas and process industries.Mr. Mattson joined Baker International, Inc. in 1980, and served in a number of capacities, including Treasurer, prior to the merger of Baker International, Inc. and Hughes Tool Company in 1987, at which time he became Vice President and Treasurer of Baker Hughes, Inc., a position he held until 1993.

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Additional Directorships:    Mr. Mattson has served as a director of National Oilwell Varco, Inc. since March 2005 (having served as a director of Varco (and its predecessor, Tuboscope Inc.) from January 1994 until its merger with National Oilwell Varco in March 2005). He served as a director of Rex Energy Corporation from April 2010 until November 2018.

Qualifications:    Mr. Mattson brings strong executive leadership skills and financial and risk management experience to the Board. His knowledge of the oil industry as well as the financial and capital markets enables him to provide critical insight to the Board.
Partner at Akin Gump Strauss Hauer & Feld LLP

Business Experience:
Ms. LaFollette has served as a partner at Akin Gump Strauss Hauer & Feld LLP since June 2004. Prior to that, Ms. LaFollette served as a partner at King & Spalding LLP from 1997 to June 2004, as a partner at Andrews & Kurth LLP from 1987 to 1997 and as an associate at Andrews & Kurth LLP from 1980 to 1987.

Qualifications:
Ms. LaFollette’s experience as a transactional and securities attorney provides her with valuable insight into corporate finance, global compliance, and governance matters. In addition, Ms. LaFollette brings to the Board a broad range of experiences and skills as a result of her involvement in numerous charitable, community and civic activities.



Eric L. Mattson
Mark A. PetersenDirector effectivesince March 1, 2018. 2022.Age 66.61.


Principal Occupation:
Principal Occupation:Former Vice President, Transportation of Sinclair Oil LLC (formerly known as Sinclair Oil Corporation) and former Director and President of each of Sinclair Trucking Company LLC and Sinclair Transportation.

Business Experience:Mr. Petersen served as Vice President, Transportation of Sinclair Oil LLC from January 2010 until the acquisition of Sinclair Oil LLC by HF Sinclair in March 2022 and Director and President of each of Sinclair Trucking Company LLC and Sinclair Transportation from August 2009 until the acquisition of Sinclair Trucking Company LLC by HF Sinclair and the acquisition of Sinclair Transportation by HEP, in each case, in March 2022. He also previously served as an officer and director of certain other Sinclair Transportation subsidiaries and joint ventures.Mr. Petersen first joined Sinclair in 1989 as a Project Engineer and held roles of increasing responsibility thereafter.

Qualifications:    Mr. Petersen brings extensive experience in the midstream sector and significant experience leading pipeline and terminal facility expansions and acquisitions to the Board.

Unitholders Agreement:    Pursuant to the Unitholders Agreement (as defined below), REH Company nominated Mark Petersen for service as the REH Company designee on the Board. Please see "Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Transactions with REH Company" for a discussion of the terms of Mr. Petersen's appointment pursuant to the Unitholders Agreement.

Executive Vice President, Finance of Select Energy Services, Inc.

Business Experience:
Mr. Mattson has served as Executive Vice President, Finance of Select Energy Services, Inc., a provider of total water solutions to the U.S. unconventional oil and gas industry, since November 2016 and served as Executive Vice President and Chief Financial Officer of Select Energy Services, Inc. from November 2008 through January 2016. Prior to that, Mr. Mattson served as Senior Vice President and Chief Financial Officer of VeriCenter, Inc., a private provider of managed hosting services, from 2003 until its acquisition in August, 2007. Mr. Mattson worked as an independent consultant from November 2002 to October 2003. Mr. Mattson served as the Chief Financial Officer of Netrail, Inc., a private Internet backbone and broadband service provider, from September 1999 until November 2002. From July 1993 until May 1999, Mr. Mattson served as Senior Vice President and Chief Financial Officer of Baker Hughes Incorporated, a provider of products and services to the oil, gas and process industries. Mr. Mattson joined Baker International, Inc. in 1980, and served in a number of capacities, including Treasurer, prior to the merger of Baker International, Inc. and Hughes Tool Company in 1987, at which time he became Vice President and Treasurer of Baker Hughes, Inc., a position he held until 1993.

Additional Directorships:Mr. Mattson has served as a director of National Oilwell Varco, Inc. since March 2005 (having served as a director of Varco (and its predecessor, Tuboscope Inc.) from January 1994 until its merger with National Oilwell Varco in March 2005) and as a director of Rex Energy Corporation since April 2010.

Qualifications:
Mr. Mattson brings strong executive leadership skills and financial and risk management experience to the Board. His knowledge of the oil industry as well as the financial and capital markets enables him to provide critical insight to the Board.




None of our directors reported any litigation for the period from 20082013 to 20182023 that is required to be reported in this Annual Report on Form 10-K. There are no family relationships among any of our directors or executive officers.




The Board


Under the Company’sHLS Governance Guidelines, Board members are expected to prepare for, attend and participate in all meetings of the Board and Board committees on which they serve. During 2017,2022, the Board held 17eleven meetings. Each director attended at least 75% of the total number of meetings of the Board and committees on which he or she served.


Board Committees


The Board currently has three standing committees:


•an Audit Committee;
•a Compensation Committee; and
•a Conflicts Committee.


Each of these committees operates under a written charter adopted by the Board.


During 2017,2022, the Audit Committee held ninetwelve meetings, the Conflicts Committee held 16five meetings, and the Compensation Committee held four meetings.

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The Board appoints committee members annually.The following table sets forth the current composition of our committees:


Name (1)
Audit

Committee
Compensation

Committee
Conflicts

Committee
Larry R. Baldwin             x (Chair)x
George J. Damirisx
R. Kevin Hardagex
Michael C. Jennings
     x (Chair)
James H. Leexx
(1)
________________________
(1)Christine B. LaFolletteEffective February 28, 2018, Mr. Hardage will resign from the Board. Effective March 1, 2018, Ms. LaFollette will serve on the Compensation Committee and the Conflicts Committee, and Mr.             x (Chair)x
James H. Leexx
Eric L. Mattson will serve on the Conflicts Committee, as Chairman, and the Audit Committee.x            x (Chair)
Mark A. Petersenx


(1) Mr. Jennings served as Chairperson of the Compensation Committee for a portion of 2022 from January 1, 2022 to April 27, 2022.


Audit Committee


The functions of the Audit Committee pursuant to its charter include the following:


•selecting, compensating, retaining and overseeing our independent registered public accounting firm and conducting an annual review of the independence and performance of that firm;


•confirming with the independent registered public accounting firm its compliance with the partner rotation requirements established by the SEC;

•reviewing and evaluating the lead partner of the independent registered public accounting firm;

•reviewing the scope and the planning of the annual audit performed by the independent registered public accounting firm;


•overseeing matters related to the internal audit function;


•reviewing and discussing with the internal auditor any issues that the internal auditor believes warrant the Audit Committee’s attention, any significant reports to management prepared by the internal auditor and any responses from management;

•reviewing the audit report issued by the independent registered public accounting firm;


•reviewing HEP’s annual and quarterly financial statements with management and the independent registered public accounting firm;


•discussing with management HEP’s significant financial risk exposures and the actions management has taken to monitor and control such exposures;


•reviewing and, if appropriate, approving transactions involving conflicts of interest, including related party transactions, when required by HEP’sconsistent with the Code of Business Conduct and Ethics;Related Party Transaction Policy;


•reviewing the Related Party Transaction Policy on an annual basis;

•reviewing and discussing HEP’s internal controls over financial reporting with management and the independent registered public accounting firm;




•establishing procedures for the receipt, retention and treatment of complaints received by HEP regarding accounting, internal accounting controls or accounting matters, potential violations of applicable laws, rules and regulations or of our codes, policies and procedures;

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•reviewing the type and extent of any non-audit work to be performed by the independent registered public accounting firm and its compatibility with their continued objectivity and independence, and to the extent consistent, pre-approving all non-audit services to be performed;


•reviewing and approving the Audit Committee Report to be included in the Annual Report ofon Form 10-K; and


•reviewing the adequacy of the Audit Committee charter on an annual basis.


Each current member of the Audit Committee and Mr. Mattson havehas the ability to read and understand fundamental financial statements. The Board has determined that Mr. Baldwin meets the requirements of an “audit committee financial expert”as defined by the rules of the SEC.


Conflicts Committee


The functions of the Conflicts Committee include reviewing specific matters that the Board or the Conflicts Committee believes may involve conflicts of interest with HFC.HF Sinclair. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to HEP. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the Conflicts Committee reviews the adequacy of the Conflicts Committee charter on an annual basis.


Compensation Committee


The functions of the Compensation Committee pursuant to its charter include:


•reviewing and approving the goals and objectives of HLS and HEP relevant to the compensation of the officers of HLS for whom the Compensation Committee determines compensation;


•determining compensation for the officers of HLS for whom the Compensation Committee determines compensation;


•reviewing director compensation and making recommendations to the Board regarding the same;


•overseeing the preparation of the Compensation Discussion and Analysis to be included in the Annual Report and preparing the Compensation Committee Report to be included in the Annual Report;


•reviewing the Company’s executive compensation plans with respect to behavioral, operational and other risks;


•administering and making recommendations to the Board with respect to HEP’s equity plan and HLS’s annual incentive plan; and


•reviewing the adequacy of the Compensation Committee charter on an annual basisbasis.


During 2017,Since the Compensation Committee had a subcommitteeis not comprised of Mr. Lee, who is “independent” as defined by the NYSE listing standards, for purposes of approvingall independent directors, equity awards, including performance goals applicable to such awards, if applicable, and any other matters that are within the responsibilities of the Compensation Committee requiring approval solely by independent members of the Board. During 2017, the subcommittee of the Compensation Committee held two meetings. Messrs. Darling, Stengel and Townsend served on the subcommittee prior to their retirement from the Board. Effective February 2018, equity awards, including performance goals applicable to such awards, if applicable, will be approved by the full Board. As a result, the subcommittee is no longer needed.
During 2017,
In January 2018, the Compensation Committee had engaged Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”Meridian Compensation Partners, LLC (“Meridian”), an executive compensation consulting firm, to advise it regardingas the compensation consultant, to provide advice relating to executive, non-employee director compensation, including benchmarking of HLS’s officersthe compensation peer group for non-employee director compensation, and directors. In selecting FWCemployee long-term equity incentive awards.At the time the Compensation Committee selected Meridian as its independent compensation consultant, and during the first quarter of every year since engaging Meridian, the Compensation Committee has assessed the independence of FWCMeridian pursuant to SEC rules and considered, among other things, whether FWCMeridian provides any other services to HLS or us, the fees paid by us to FWCMeridian as a percentage of FWC’sMeridian’s total revenues, the policies of FWCMeridian that are designed to prevent any conflict of interest between


FWC, Meridian, the Compensation Committee, HLS and us, any personal or business relationship between FWCMeridian and a member of the Compensation Committee or one of HLS’s executive officers and whether FWCMeridian owned any of our common units. In addition to the foregoing, the Compensation Committee receivedannually receives an independence letter from FWC,Meridian, as well as other documentation addressing the firm’s independence. FWCMeridian reports exclusively to the Compensation Committee and does not provide any additional services to HLS or us.The Compensation
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Committee has discussed these considerations and has concluded that FWCMeridian is independent and that neither we nor HLS have any conflicts of interest with FWC.Meridian.
In January 2018, the Compensation Committee engaged Meridian Compensation Partners, LLC (“Meridian”) to provide advice relating to non-management director compensation matters beginning with the 2018 fiscal year. Meridian did not provide any information or advice to the Compensation Committee with respect to matters related to executive and non-management director compensation in 2017.

Compensation Committee Interlocks and Insider Participation

The members of the Compensation Committee of the Board at year-end 2017 were Messrs. Jennings, Damiris and Lee. Messrs. Darling, Stengel and Townsend also served as Compensation Committee members until their retirement in November 2017. During his service as a member of the Compensation Committee, Mr. Damiris also served as the Chief Executive Officer and President of HLS. None of the members who served on the Compensation Committee at any time during 2017 had any relationship requiring disclosure under Item 13 of this annual report on Form 10-K entitled “Certain Relationships and Related Transactions, and Director Independence.” No executive officer of HLS served as a member of the compensation committee of another entity that had an executive officer serving as a member of our Board or our Compensation Committee. No executive officer of HLS served as a member of the board of another entity that had an executive officer serving as a member of our Compensation Committee, except that Mr. Damiris, the Chief Executive Officer and President of HLS, also served as the Chief Executive Officer and President of HFC.


Report of the Audit Committee for the Year Ended December 31, 20172022
 
Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.’s system of internal controls over financial reporting. The Audit Committee selected, and the Board approved the selection of, Ernst & Young LLP as Holly Energy Partners, L.P.’s independent registered public accounting firm to audit the books, records and accounts of Holly Energy Partners, L.P. for the year ended December 31, 2017.2022.Ernst & Young LLP is responsible for performing an independent audit of Holly Energy Partners, L.P.’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (“PCAOB”) and to issue a report thereon.The Audit Committee also is responsible for selecting, engaging and overseeing the work of the independent registered public accounting firm, which reports directly to the Audit Committee, and evaluating its qualifications and performance. Among other things, to fulfill its responsibilities, the Audit Committee:
 
•reviewed and discussed Holly Energy Partners, L.P.’s quarterly unaudited consolidated financial statements and its audited annual consolidated financial statements for the year ended December 31, 20172022 with management and Ernst & Young LLP, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements, including those in management’s discussion and analysis thereof;


•discussed with Ernst & Young LLP the matters required to be discussed by Auditing Standard No. 16, Communications with Audit Committees, as adopted by the Public Company Accounting Oversight Board;applicable requirements of the PCAOB, the SEC and the NYSE;


•discussed with Ernst & Young LLP matters relating to its independence and received the written disclosures and letter from Ernst & Young LLP required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee concerning the firm’s independence;


•discussed with Holly Energy Partners, L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits and met with the internal auditors and Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of Holly Energy Partners, L.P.’s financial reporting; and


•considered whether Ernst & Young LLP’s provision of non-audit services to Holly Energy Partners, L.P. is compatible with the auditor’s independenceindependence.


The Audit Committee charter requires the Audit Committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All fees for audit, audit-related and tax services as well as all other fees


presented under Item 14 “Principal Accountant Fees and Services” were approved by the Audit Committee in accordance with its charter.


Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate, the Audit Committee recommended to the Board that the audited consolidated financial statements of Holly Energy Partners, L.P. for the year ended December 31, 20172022 be included in Holly Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 20172022 for filing with the SEC.
 
Members of the Audit Committee:
Larry R. Baldwin, Chairman
R. Kevin HardageChairperson
James H. Lee

Eric L. Mattson
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Director Compensation


The Compensation Committee annually evaluates the compensation program for members of the Board who are not officers or employees of HLS or HFCHF Sinclair (“non-employee directors”). Directors who also serve as officers or employees of HLS or HFCHF Sinclair do not receive additional compensation for serving on the Board. We reimburse directors for all reasonable expenses incurred in attending Board and Board committee meetings and director continuing education sessions upon submission of appropriate documentation. No meeting fees are paid for Board or Board committee meetings.


For 2017,2022, non-employee directors were entitled to receive aan annual cash retainer, and meeting fees payable in cash, in addition to an annual equity awardsretainer in the form of an award of phantom units described in the following table.table below.


Larry R. Baldwin has served as Presiding Director of HLS since February 2020 when Mr. Jennings, Chairperson of the Board of HLS, became an executive officer of HF Sinclair and HLS. As an executive officer of HF Sinclair and HLS, Mr. Jennings does not receive any compensation for his service on the Board.

In November 2017,October 2022, the Board approved non-employee director compensation for 2018. For 2018, the Board eliminated meeting fees until the thirteenth meeting of the Board or the Committee. As a result, several2023. There were no changes from 2022. The awards that were made to the equity and cash payments received by the non-employee directors, which are reflectedgranted in October 2022 (for 2023 services) were in the table below.form of phantom units.


 Compensation in 2017 (1)Compensation in 2018 (1)
Annual cash retainer$60,000$100,000
Meeting fee (also paid to non-members of committees who are invited to attend by such committee’s chairman) (2)$1,500$1,500
Annual equity retainer of restricted units (3)$80,000$90,000
Annual cash retainer for the Chairman of the Board$100,000$75,000
Annual cash retainer for Chairmen of committees and subcommittees$15,000$25,000 (4)
Compensation in 2022Compensation in 2023
Annual cash retainer$100,000 $100,000 
Annual cash retainer for the Presiding Director$25,000 $25,000 
Annual equity retainer (1)
$115,000 $115,000 
Annual cash retainer for the Chairperson of the Board (2)
$75,000 $75,000 
Annual cash retainer for Chairperson of committees (2)
$25,000 $25,000 
__________________


(1)Because Mr. Hardage was appointed to fill a temporary vacancy on the HLS Board, Mr. Hardage did not participate in the non-employee director compensation program. Instead, he received cash compensation of $18,000 per month for his service on the Board.
(2)Represents fees paid for meetings attended in person or telephonically. Beginning in 2018, no meeting fees will be paid for the first 12 Board or Committee meetings. Meeting fees will be paid beginning with the thirteenth meeting of the Board or Committee.
(3)
The annual award is comprised of a number of restrictedphantom units equal to the annual equity retainer divided by the closing price of a common unit on the date of grant, with the number of restrictedphantom units rounded up in the case of fractional shares.
(4)(2)Beginning in 2018, no cash retainer will be paid toAs an executive officer of HF Sinclair and HLS, Mr. Jennings does not receive any compensation for serving as Chairperson of the ChairmanBoard and did not receive any compensation for the portion of the 2022 fiscal year during which he served as Chairperson of the Compensation Committee since he also serves as Chairman of the Board.HLS.


Annual Equity Awards


Non-employee directors receive an annual equity award grant under the Holly Energy Partners, L.P. Amended and Restated Long-Term Incentive Plan (“Long-Term(the “Long-Term Incentive Plan”) in the form of restrictedphantom units, with the number of restricted unitsawards calculated as described above. Continued service on the Board through the vesting date, which is approximately one year following the date of grant, is required for the restricted unitsawards to vest. Vesting of all unvested units will accelerate upon a change in control of HFC,HF Sinclair, HLS, HEP or HEP Logistics. In addition, vesting of unvested units will accelerate on a pro-rata basis upon the director’s death, total and permanent disability or retirement. Directors are entitled to receive all distributionsdistribution equivalents paid with respect to outstanding


restricted awards, and these distribution equivalents are paid at approximately the same time as distributions are paid on our common units. The distributionsdistribution equivalents are not subject to forfeiture. The directors also have a right to vote with respect to the restricted units.


Non-Qualified Deferred Compensation


Non-employee directors are eligible to participate in the HollyFrontierHF Sinclair Corporation Executive Nonqualified Deferred Compensation Plan, which is not tax-qualified under Section 401 of the Internal Revenue Code and allows participants to defer receipt of certain compensation (the “NQDC Plan”). The NQDC Plan allows non-employee directors the ability to defer up to 100% of their cash retainers and meeting fees for a calendar year. Participating directors have full discretion over how their contributions to the NQDC Plan are invested among the investment options. Earnings on amounts contributed to the NQDC Plan are calculated in the same manner and at the same rate as earnings on actual investments. Neither HLS nor HFCHF Sinclair subsidizes a participant’s earnings under the NQDC Plan.


None of our
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Mr. Petersen was the only non-employee directorsdirector who participated in the NQDC Plan in 2017.2022. For additional information on the NQDC Plan, see “Compensation Discussion and Analysis-OverviewAnalysis–Overview of 20172022 Executive Compensation Components and Decisions-RetirementDecisions–Retirement and Benefit Plans-DeferredPlans–Deferred Compensation Plan” and thenarrative preceding the “Nonqualified Deferred Compensation Table.”


Unit Ownership and Retention Policy for Directors


Effective October 2013, ourOur directors, becameother than those who serve as officers of HLS, are subject to a newthe HEP unit ownership and retention policy. Pursuant to the policy, each director is required to hold during service on the Board common units equal in value to at least twothree times the annual equity retainer paid to non-employee directors. As of January 1, 2017, each non-employee director was required to hold common units equal in value to $160,000. Beginning in November 2017, each non-employee director was required to hold common units equal in value to $180,000. Each subject director is required to meet the applicable requirements within five years of first being subject to the policy.


Directors are also required to continuously own sufficient units to meet the unit ownership and retention requirements once attained. Until directors meet the requirements, they will be required to hold 25% of the units received from any equity award. If a director attains compliance with the policy and subsequently falls below the requirement because of a decrease in the price of our common units, the director will be deemed in compliance provided that the director retains the units then held.


As of December 31, 2017,2022, all of our then-current directors were in compliance with the unit ownership and retention policy or were within the five-year grace period provided in the policy.


Anti-Hedging and Anti-Pledging Policy


MembersAll of the Boardour directors are subject to the HEPour Insider Trading Policy, which, among other things, prohibits such directors from entering into short sales or hedging or pledging our common units and HFCHF Sinclair common stock. The anti-hedging policy contained in our Insider Trading Policy specifically prohibits directors and their designees from purchasing financial instruments or otherwise engaging in transactions that hedge or offset or are designed to hedge or offset any decrease in the market value of HEP or HF Sinclair securities (or derivatives thereof), including through, among other mechanisms, the purchase of financial instruments (such as prepaid variable forward contracts, equity swaps, collars, and exchange funds) or other transactions that are designed to hedge or offset any decrease in the market value of our securities. Additionally, all employees, including our named executive officers, are prohibited from holding our securities in a margin account or otherwise pledging our securities as collateral for a loan.


Director Compensation Table


The table below sets forth the compensation earned in 20172022 by each of the non-employee directors of HLS:


Name (1)Fees Earned or Paid in CashUnit Awards (2)All Other CompensationTotal
Larry R. Baldwin$138,000$90,026—
$228,026
Matthew P. Clifton (3)218,500
80,003
$160,705 (4)
459,208
Charles M. Darling, IV (3)133,500
80,003
160,705 (4)
374,208
R. Kevin Hardage (5)(6)28,200
—
—
28,200
Michael C. Jennings120,630
90,026
—
210,656
James H. Lee (5)12,978
90,032
—
103,010
Jerry W. Pinkerton (3)49,500
—
—
49,500
William P. Stengel (3)126,000
80,003
160,705 (4)
366,708
James G. Townsend (3)106,500
80,003
160,705 (4)
347,208
Name (1)
Fees Earned or Paid in Cash
Unit Awards (2) (3)
Total
Larry R. Baldwin$150,000 $115,005 $265,005 
Christine B. LaFollette$116,896 $115,005 $231,901 
James H. Lee$100,000 $115,005 $215,005 
Eric L. Mattson$125,000 $115,005 $240,005 
Mark A. Petersen (3)
$79,722 $190,043 $269,765 
__________________



(1)     Mr. Jennings is not included in this table because he received no additional compensation for his service on the Board during 2022, since he was an executive officer of HF Sinclair and HLS. The compensation paid by HF Sinclair to Mr. Jennings in 2022 will be shown in HF Sinclair’s 2023 Proxy Statement. A portion of the compensation paid to Mr. Jennings by HF Sinclair in 2022 is allocated to the services he performed for us in his capacity as an executive officer of HLS and is disclosed in the “Summary Compensation Table” below.

(1)Mr. Damiris is not included in this table because he received no additional compensation for his service on the Board since, during 2017, Mr. Damiris was an executive officer of HFC and HLS. The compensation paid by HFC to Mr. Damiris in 2017 will be shown in HFC’s 2018 Proxy Statement. A portion of the compensation paid to Mr. Damiris by HFC in 2017 is allocated to the services he performed for us in his capacity as an executive officer of HLS and is disclosed in the “Summary Compensation Table” below. Ms. LaFollette and Mr. Mattson are not included in the table because they did not serve as directors in 2017.

(2)Reflects the aggregate grant date fair value of restricted units granted to non-employee directors, computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), determined without regard to forfeitures. See Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2017, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.


On November 1, 2017, Messrs. Baldwin, Clifton, Darling, Jennings, Stengel(2)    With the exception of Mr. Petersen, reflects the aggregate grant date fair value of 6,150 phantom units granted to the non-employee directors on October 25, 2022 (the "2023 Director Awards"), computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), determined without regard to forfeitures. See Note 9 to our consolidated financial statements for the fiscal year ended December 31, 2022, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

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Because the 2023 Director Awards were granted during 2022, they are reported in the "Unit Awards" column of the Director Compensation Table for 2022 rather than 2023 in accordance with SEC rules. The annual phantom unit awards for the 2022 fiscal year were granted on October 27, 2021 and Townsend received an awardwere reported in the "Unit Awards" column of 2,246 restricted units that veststhe Director Compensation Table for 2021 rather than 2022 in accordance with SEC rules.

The 2023 Director Awards vest on December 1, 2018,2023, subject to continued service on the Board. Messrs. Clifton, Darling, Stengel and Townsend forfeited these restricted units in connection with their retirement from the Board on November 9, 2017. On November 10, 2017, Mr. Lee received an award of 2,443 restricted units that vests on December 1, 2018, subject to continued service on the Board, in connection with his appointment to the Board. On November 15, 2017, the Board approved an increase in the director equity retainer for 2018 from $80,000 to $90,000. As a result, on November 15, 2017, Messrs. Baldwin, Jennings and Lee received an additional award of 311 restricted units that vests on December 1, 2018, subject to continued service on the Board, since their prior awards in 2017 were based on a grant value of $80,000. As of December 31, 2017, Messrs. Baldwin and Jennings2022, these are the only phantom units held 2,557 restricted units and Mr. Lee held 2,754 restricted units. Mr. Hardage was not eligible to receive a grant of equity awards.by our non-employee directors. For additional information regarding the annual restrictedphantom unit grants, please refer to the “Director Compensation”"Director Compensation" narrative above.
(3)In accordance with our director retirement policy, Mr. Pinkerton resigned from the Board effective June 30, 2017. On November 9, 2017, Messrs. Clifton, Darling, Stengel and Townsend retired from the Board. Each of them is included in the table since he served as a non-employee director during 2017.

(4)Represents cash payment made to the director at the time of retirement as compensation for forfeited restricted units as a result of his retirement.

(5)Mr. Lee was appointed to the Board effective November 10, 2017. Mr. Hardage was appointed to the Board effective November 14, 2017.

(6)Because Mr. Hardage was appointed to fill a temporary vacancy on the HLS Board, he did not participate in the director compensation program and instead received $18,000 per month for his service on the Board.


Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a)(3)    Mr. Petersen was appointed to the HLS Board on March 15, 2022. He received a pro-rated cash retainer for the portion of the Exchange Act requires directors, executive officers2022 fiscal year that he served as a non-employee director of HLS, all of which he elected to defer pursuant to the NQDC Plan described above under "NonQualified Deferred Compensation Plan." There are no earnings reported for Mr. Petersen for any portion of the 2022 year with respect to the NQDC Plan, as no earnings are deemed to be above-market or preferential for that plan. Subsequent to Mr. Petersen's appointment, on April 27, 2022, he received a pro-rated equity award of 4,313 phantom units that vested on December 1, 2022 to compensate him for the portion of the 2022 fiscal year that he served as a non-employee director of HLS (the "Pro-rated 2022 Director Award"). On October 25, 2022, Mr. Petersen also received a 2023 Director Award for the 2023 fiscal year. Therefore, the amount reported for Mr. Petersen in the "Unit Awards" column in the table above reflects the aggregate grant date fair value of this Pro-rated 2022 Director Award and persons who beneficially own more than 10% of HEP’s unitshis 2023 Director Award, each computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 ("FASB ASC Topic 718"), determined without regard to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of HEP’s equity securities. Based on a review of these reports, other information available to us and written representations from reporting persons indicating that no other reports were required, all such reports concerning beneficial ownership were filed in a timely manner by reporting persons during the year ended December 31, 2017.forfeitures.


Item 11. Executive Compensation


Compensation Discussion and Analysis


This Compensation Discussion and Analysis provides information about our compensation objectives and policies for the HLS executive officers who are our “Named Executive Officers” for 20172022 to the extent the Compensation Committee and the Board, or our Chief Executive Officer determines the compensation of these individuals and about the compensation for our other Named Executive Officers that is allocated to us pursuant to Compensation Committee action or SEC rules. In addition, the Compensation Discussion and Analysis is intended to place in perspective the information contained in the executive compensation tables that follow this discussion and provide a description of our policies relating to reimbursement to HFCHF Sinclair and HLS for compensation expenses.




Overview


We are managed by HLS, the general partner of HEP Logistics, our general partner. HLS is a subsidiary of HFC.HF Sinclair. The employees providing services to us are either provided by HLS, which utilizes people employed by HFCHF Sinclair to perform services for us, or seconded to us by subsidiaries of HFC,HF Sinclair, as we do not have any employees.


For 2017,2022, our “Named Executive Officers” were:


NamePosition with HLS in 20172022
George J. DamirisMichael C. JenningsChief Executive Officer and President
Richard L. Voliva IIIJohn HarrisonExecutiveSenior Vice President, and Chief Financial Officer and Treasurer
Mark T. CunninghamVaishali S. BhatiaSenior Vice President, Engineering and Technical Services (1)
Denise C. McWattersSenior Vice President, General Counsel and Secretary
_______________
Mark T. Cunningham(1)
Mr. Cunningham was appointedFormer Senior Vice President, Operations and Engineering in January 2018.
Richard L. Voliva III(2)
Former President

Certain


(1)    Mr. Cunningham retired as Senior Vice President, Operations and Engineering of HLS effective February 18, 2022 (referred to herein as his “Retirement”). See the section below titled “Potential Payments Upon Termination or Change in Control - Retirement & Consulting Arrangements with Mr. Cunningham” for additional information regarding his
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Retirement.Although he was no longer employed at the end of the 2022 year, he is still deemed to be a Named Executive Officer pursuant to SEC disclosure rules.

(2)    HLS and Richard L. Voliva III, President of HLS, agreed to a mutual separation effective September 15, 2022. As a result of Mr. Voliva's separation, the Board appointed Michael C. Jennings as President of HLS, effective as of September 15, 2022. See the section below titled "Potential Payments Upon Termination or Change in Control - Mutual Separation Agreement with Mr. Voliva" for additional information regarding his separation. Although he was no longer employed at the end of the 2022 year, he is still deemed to be a Named Executive Officer pursuant to SEC disclosure rules.


During the period of their employment during 2022, certain of our Named Executive Officers arewere also officers of HFCHF Sinclair or provideprovided services to HFC.HF Sinclair. During 2017:2022:


•Prior to his Retirement, Mr. Cunningham spent all of his professional time managing our business and affairs and did not provide any services to HFC.HF Sinclair.

•Messrs. DamirisJennings and VolivaHarrison and Ms. McWatters,Bhatia, and prior to his separation, Mr. Voliva, who we generally refer to as the “HFC“HF Sinclair Shared Officers,” also served as executive officers of HFCHF Sinclair and devoted as much of their professional time as was necessary to oversee the management of our business and affairs. All compensation paid to such executive officers by HF Sinclair is paid and determined by HFC,HF Sinclair, without input from the Compensation Committee. For 2022, Mr. Voliva was the only HF Sinclair Shared Officer that received direct compensation from us as discussed below.


As noted above, Mr. Jamieson was appointed to the position of Senior Vice President and Chief Operating Officer during the 2023 year and is listed as an executive officer in other sections of this annual report. However, due to the timing of his appointment, he is not deemed to be a Named Executive Officer for the 2022 year.

Compensation Committee Interlocks and Insider Participation

The members of the Compensation Committee of the Board are Messrs. Jennings, Lee and Petersen and Ms. LaFollette. Mr. Jennings also serves as the Chief Executive Officer and President of HLS. Mr. Petersen was nominated to serve on the Board by REH Company pursuant to the terms of the Unitholders Agreement and provided consulting services to HF Sinclair in 2022 pursuant to the terms of a consulting agreement with HF Sinclair, each of which are discussed in detail under Item 13 of this Annual Report on Form 10-K entitled “Certain Relationships and Related Transactions, and Director Independence.” With the exception of the relationships disclosed for Mr. Petersen, none of the members who served on the Compensation Committee at any time during 2022 had any relationship requiring disclosure under Item 13 of this Annual Report on Form 10-K entitled “Certain Relationships and Related Transactions, and Director Independence.” No executive officer of HLS served as a member of the compensation committee of another entity that had an executive officer serving as a member of our Board or our Compensation Committee. No executive officer of HLS served as a member of the board of another entity that had an executive officer serving as a member of our Compensation Committee, except that Mr. Jennings also serves as the Chief Executive Officer of HF Sinclair.

Fees and Reimbursements for Compensation of Named Executive Officers


•Administrative Fee Covers HFCHF Sinclair Shared Officers. Under the terms of the Omnibus Agreement we pay an annual administrative fee to HFCHF Sinclair (currently $2.5$5.0 million) for the provision of general and administrative services for our benefit, which may be increased or decreased as permitted under the Omnibus Agreement. The administrative services covered by the Omnibus Agreement include, without limitation, the costs of corporate services provided to us by HFCHF Sinclair such as accounting, tax, information technology, human resources, in-house legal support and office space, furnishings and equipment. None of the services covered by the administrative fee isare assigned any particular value individually. Although the administrative fee covers the services provided to us by the Named Executive Officers who are HFCHF Sinclair Shared Officers, no portion of the administrative fee is specifically allocated to services provided by those Named Executive Officers to us. Rather, the administrative fee generally covers services provided to us by HFCHF Sinclair and, except as described below, there is no reimbursement by us for the specific costs of such services. Typically we reflect our allocated amounts into cash compensation columns of the Summary Compensation Table, namely within the Base Salary column. For the 2022 year, the portion of compensation for certain Named Executive Officers exceeded base salaries, so there was a portion of compensation allocations that were reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table reflecting amounts earned pursuant to the HF Sinclair annual incentive bonus plan. A discussion
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of the non-equity incentive compensation payable by HF Sinclair will be disclosed in HF Sinclair’s 2023 Proxy Statement. See Item 13, “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report on Form 10-K for additional discussion of our relationships and transactions with HFC.
HF Sinclair.


•Reimbursements for Compensation of Dedicated HLS Officers. Under the Omnibus Agreement, we also reimburse HFCHF Sinclair for certain expenses incurred on our behalf, such as for salaries and employee benefits for certain personnel employed by HFCHF Sinclair who perform services for us on behalf of HLS, including the dedicated HLS officers, as described in greater detail below. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. In 2017,2022, we reimbursed HFCHF Sinclair for 100% of the compensation expenses incurred by HFCHF Sinclair for salary, bonus, retirement and other benefits provided to Mr. Cunningham. With respect to equity compensation paid by us to Mr. Cunningham and Mr. Voliva, HLS purchases the units delivered pursuant to awards under our Long-Term Incentive Plan, and we reimburse HLS for the purchase price of the units.


CompensatoryCompensation Decisions for Dedicated HLS Officers


•Generally. The Compensation Committee, generally makespursuant to its charter, determines cash and bonus compensation decisionsonly for HLS’s Chief Executive Officer, President or Chief Financial Officer if such officers are solely dedicated to HLS and are not HF Sinclair Shared Officers. During 2022, HLS’s Chief Executive Officer, President and Chief Financial Officer were HF Sinclair Shared Officers, and as a result, the Compensation Committee did not set cash and bonus compensation for any executive officer. For 2022, the Compensation Committee made compensation recommendations, which were subsequently approved by the Board, for Mr. Cunningham only with respect to the terms of his consulting arrangement with HLS following his Retirement. The terms of Mr. Cunningham's consulting arrangement with HLS are described in the section below titled "Potential Payments Upon Termination or Change in Control - Retirement & Consulting Arrangements with Mr. Cunningham." All other compensation provided to Mr. Cunningham for 2022, other than with respect to pension and retirement benefits as described below. All compensation provided to Mr. Cunningham for 2017below, was determined by the Chief Executive Officer and President of HLS and is discussed and reported, in accordance with SEC rules, in the narratives and tables that follow.




•Pension and Retirement Benefits. The Compensation Committee does not review or approve pension or retirement benefits for any of the Named Executive Officers. Rather, all pension and retirement benefits provided to the executives are the same pension and retirement benefits that are provided to employees of HFCHF Sinclair generally, and such benefits are sponsored and administered entirely by HFCHF Sinclair without input from HLS or the Compensation Committee. The pension and retirement benefits provided to Mr. Cunningham in 20172022 are described below and were charged to us monthly in accordance with the Omnibus Agreement.


Allocation of Compensation and CompensatoryCompensation Decisions for HFCHF Sinclair Shared Officers


•Generally. HFCHF Sinclair makes all decisions regarding the compensation paid to the HFCHF Sinclair Shared Officers, which compensation is covered by the administrative fee under the Omnibus Agreement (and therefore not subject to reimbursement by us); however, in accordance with SEC rules, for purposes of these disclosures, a portion of the compensation paid by HFCHF Sinclair to the HFCHF Sinclair Shared Officers for 20172022 is allocated to the services they performed for us during 2017.2022. The allocation was made based on the assumption that each of Messrs. DamirisJennings and VolivaHarrison and Ms. McWattersBhatia, and Mr. Voliva, prior to his separation, spent, in the aggregate, the following percentage of his or her professional time on our business and affairs in 2017:
2022:


NamePercentage of Time
George J. DamirisMichael C. Jennings20%25%
John Harrison25%
Richard L. Voliva III20%35%
Denise C. McWattersVaishali S. Bhatia30%25%




Because HFCHF Sinclair made all decisions regarding the compensation paid to Messrs. Damiris andJennings, Voliva and Harrison and Ms. McWattersBhatia for 2017,2022, except for the decision regarding Mr. Voliva’s participation in HEP’s annual cash incentive program as a result of his expanded responsibilities with HLS and HEP in 2022, those decisions are not discussed in this Compensation Discussion and Analysis. The total compensation paid by HFCHF Sinclair to Messrs. DamirisJennings and Voliva and Ms. McWattersBhatia in 20172022 will be
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disclosed in HFC’s 2018HF Sinclair ’s 2023 Proxy Statement.The compensation paid by HF Sinclair to Mr. Harrison is discussed and disclosed in the tables that follow.


Objectives of Compensation Program


Our compensation program is designed to attract and retain talented and productive executives who are motivated to protect and enhance our long-term value for the benefit of our unitholders. Our objective is to be competitive with our industry and encourage high levels of performance from our executives.


In supporting our objectives, in applicable years, the Compensation Committee balancesconsiders the use of cash andcompensation to be received by the dedicated HLS officers when determining equity compensation in the total direct compensation package provided tofor the dedicated HLS officers; however, the Compensation Committee has not adopted any formal policies for allocating their compensation among salary, bonus and long-term equity compensation.


In the fourth quarter of 2016,2021, the Compensation Committee, with the assistance of the Chief Executive Officer and President, reviewed the mix and level of cash and long-term equity incentive compensationconsulting arrangement for Mr. Cunningham with a goal of providing competitiveretaining his expertise to facilitate an orderly transition of his responsibilities following his Retirement. In addition, in the fourth quarter of 2021, the Chief Executive Officer reviewed the contributions and responsibilities of Mr. Voliva, and made the decision that Mr. Voliva would participate in HEP’s annual incentive cash compensation program for 2017 to retain him, while at the same time providing him incentives to maximize long-term value2022 in light of his increased responsibilities for usHLS and our unitholders. After reviewing internal evaluations, input by management, and market data provided by the Compensation Consultant, the Compensation Committee believes that the 2017 compensation paid toHEP following Mr. Cunningham reflects an appropriate allocation of compensation between salary, bonus and equity compensation.Cunningham’s Retirement.


Role of the Compensation Consultant and the CompensationCommittee in the Compensation Setting Process


In 2017,Since 2018, the Compensation Committee has retained Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”),Meridian, a consulting firm specializing in executive compensation, to advise the Compensation Committee on matters related to executive and non-employee director compensation, including benchmarking of the compensation peer group for non-employee director compensation, and long-term equity incentive awards. The Compensation Consultant provided the Compensation Committee with market data, updates on related trends and developments, advice on program design, and input on compensation decisions for executive officers and non-employee directors. As discussed above under “-The“The Board, Its Committees and Director Compensation-Board Committees-CompensationCompensation–Board Committees–Compensation Committee,” the Compensation Committee has concluded that we do not have any conflicts of interest with FWC.Meridian.


The Compensation Committee generally makes compensation decisions for a given fiscal year in the fourth quarter of the prior year. The Compensation Consultant does not have authority to determine the ultimate compensation paid to executive officers or non-employee directors, and the Compensation Committee is under no obligation to utilize the information provided by the Compensation Consultant when making compensation decisions. The Compensation Consultant provides external context and


other input to the Compensation Committee prior to the Compensation Committee approving salaries and fees, awarding bonuses and equity compensation or establishing awards for the upcoming year.

In January 2018, the Compensation Committee engaged Meridian Compensation Partners, LLC (“Meridian”). Meridian did not provide anyprovided information orand advice to the Compensation Committee in 2021 and 2022 with respect to 2017matters related to executive compensation related trends, regulatory and legislative developments, review of the compensation benchmarking peer group and performance peer group for long-term incentive plan performance comparisons, benchmarking of non-employee director compensation, and development of a severance pay plan. The Compensation Committee is aware that Meridian is also providing similar services to the compensation committee at HF Sinclair but our Compensation Committee manages its relationship with Meridian independently of the relationship that Meridian has with the HF Sinclair compensation committee. The aggregate amount of fees HLS paid to Meridian for the services it engaged Meridian to perform during the 2022 fiscal year was approximately $26,213. The aggregate amount of fees HF Sinclair paid to Meridian for the services it engaged Meridian to perform during the 2022 fiscal year was approximately $278,686.

The Compensation Committee, pursuant to its charter, determines cash and annual incentive compensation for only HLS’s Chief Executive Officer, President or Chief Financial Officer, if such officers are solely dedicated to HLS and are not HF Sinclair Shared Officers. For all HLS officers who are eligible to receive equity awards under HEP’s equity plans, the Compensation Committee will review and recommend to the Board for approval, long-term equity incentive compensation.


Review of Market Data


Market pay levels are one of many factors considered by the Compensation Committee in setting equity compensation for the Named Executive Officers. TheIn 2021, the Compensation Committee regularly reviewsreviewed comparison data provided by the Compensation Consultant with respect to salary, annual incentive levels and long-term incentive levels as one point of reference in evaluating the reasonableness and competitiveness of the incentive compensation paid to our executive officers as compared to companies
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with which we compete for executive talent. In addition, the Compensation Committee reviewsreviewed such data to evaluate whether our incentive compensation reflects practices of comparable companies of generally similar size and scope of operations. The Compensation Consultant obtainsobtained market information primarily from SEC filings of publicly traded companies that the Compensation Consultant and the Compensation Committee consider appropriate peer group companies and, from time to time, from published compensation surveys (such asthe Liquid Pipeline Roundtable Compensation Survey). The purpose of the peer group is to provide a frame of reference with respect to executive equity compensation at companies of generally comparable size and scope of operations, rather than to set specific benchmarks for the compensation provided to the Named Executive Officers. We select peer group companies that we believe provide relevant data points for our consideration.


The peer group used in determining 20172022 equity compensation included the following publicly traded master limited partnerships,companies, which are representative of the companies with which we compete for executives:talent:


Boardwalk PipelineAntero Midstream CorporationEnable Midstream Partners, LP
Black Stone Minerals, L.P.NGL EnergyEnLink Midstream, LLC
Callon Petroleum CompanyPhillips 66 Partners LP
Calumet Specialty ProductsCentennial Resource Development, Inc.Shell Midstream Partners, LPNuStar Energy LPL.P.
Crestwood Equity Partners LPRose Rock Midstream LP
DCP Midstream Partners LPSummit Midstream Partners, LP
 EnLink MidstreamDelek Logistics Partners, LPTarga Resources Partners LP
Genesis Energy LPUSA Compression Partners LP


The peer group used in 2017for 2022 compensation was changedreduced by one company from the peer group used in 2016with respect to 2021 compensation due to merger activity.activity and recommendations from the Compensation Consultant.


OurFor years in which we make the compensation decisions for our executive officers, our objective generally is to position pay at levels approximately in the middle range of market practice, taking into account median levels derived from our peer group analysis. Following advice from the Compensation Consultant, we consider our salary and non-salary compensation components relative to the median compensation levels generally within the peer group rather than to an exact percentile above or below the median. For these purposes, if compensation is generally within plus or minus 20% of the market median, it is considered to be in the middle range of the market.

In 2017, the total direct compensation paid to Mr. Cunningham was generally in the middle range of the market. As noted, however, this market analysis is just one of many factors considered when making overall compensation decisions for our executives.


Role of Named Executive Officers in Determining Executive Compensation


In making executive equity compensation decisions for Named Executive Officers that are solely dedicated to HLS, the Compensation Committee typically reviews the total compensation provided to each executive in the prior year, the executive’s overall performance and market data provided by the Compensation Consultant. The Compensation Committee also considers recommendations by the Chief Executive Officer and President and other factors in determining the appropriate final equity compensation amounts.amounts to recommend to the Board.


Various members of management facilitate the Compensation Committee’s consideration of equity compensation for Named Executive Officers by providing data for the Compensation Committee’s review. This data includes, but is not limited to, performance evaluations, performance-based compensation provided to the Named Executive Officers in previous years, tax-related considerations and accounting-related considerations. Management provides the Compensation Committee with guidance as to how such data impacts performance goals set by the Compensation Committee during the previous year. Given the day-to-day familiarity that management has with the work performed, the Compensation Committee values management’s recommendations, although no Named Executive Officer has authority to determine or comment on compensation decisions directly related to himself. As described above,himself or herself. Due to the planned transition of his responsibilities effective January 1, 2022 in preparation for his Retirement, no long-term equity compensation was recommended for Mr. Cunningham for 2022. To assist with the orderly transition of Mr. Cunningham’s responsibilities following his Retirement, management recommended and the Compensation Committee makesreviewed and made a recommendation to the Board, which subsequently approved, the terms of a consulting arrangement between HLS and Mr. Cunningham for a period of 12 months commencing on February 19, 2022. See the section below titled “Potential Payments Upon Termination or Change in Control - Retirement & Consulting Arrangements with Mr. Cunningham” for a discussion of the terms of Mr. Cunningham’s consulting arrangement with HLS.

In the fourth quarter of 2021, the Chief Executive Officer and President were separate individuals. The Chief Executive Officer set 2022 compensation for his direct reports who were solely dedicated to HLS and who did not serve as President of HLS, and the President set 2022 compensation for his direct reports who were solely dedicated to HLS and who did not serve as Chief Financial Officer of HLS. In September 2022, the Board delegated authority to the Chief Executive Officer to negotiate, and to a subcommittee of the Compensation Committee to approve, the final decision as to the compensationterms of Mr. Cunningham.Voliva’s mutual separation agreement,

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specifically as it related to accelerated vesting of his outstanding phantom unit award and 2022 annual cash incentive bonus, each of which are discussed further below.


Overview of 20172022 Executive Compensation Components and Decisions


Mr. Cunningham was the only Named Executive Officer solely dedicated to HLS during 2022. In 2017,addition to the Compensation Committee madeconsulting compensation decisions forand accelerated vesting of long-term equity incentive compensation described further below in the section titled “Potential Payments Upon Termination or Change in Control - Retirement & Consulting Arrangements with Mr. Cunningham. TheCunningham” the components of compensation received by Mr. Cunningham in 20172022 are as follows:


•base salary;
•annual incentive cash bonus compensation;
long-term equity incentive compensation;
•severance and change in control benefits;
•health and retirement benefits; and
•perquisites.


Each of these components is described in further detail in the narrativenarratives and/or tables that follows.follow.


Base Salary

The Compensation Committee conducted its annual review of base salary for Mr. CunninghamIn addition, in the fourth quarter of 2016.2021, the Chief Executive Officer reviewed the contributions and responsibilities of Mr. Voliva, then President of HLS and an HF Sinclair Shared Officer, and determined that Mr. Voliva would participate in HEP’s annual incentive cash bonus compensation program for 2022 in light of his increased responsibilities for HLS and HEP following Mr. Cunningham’s Retirement. The Compensation Committeeterms of Mr. Voliva’s annual incentive cash bonus award and the determination of his final payout upon his separation are discussed below in the section titled “Annual Incentive Cash Bonus Compensation.”

Base Salary

Base salary for Mr. Cunningham for 2022 was determined by the then-current President of HLS in the fourth quarter of 2021. The President considered hisMr. Cunningham’s position, level of responsibility and performance in 2016, where applicable. The Compensation Committee also reviewed competitive market data relevant2021, and the forthcoming transition of his responsibilities to four different individuals at HLS, effective January 1, 2022, in preparation for his position provided by the Compensation Consultant.Retirement. Following a review of the various factors listed above, the Compensation Committee determined the following 2017Mr. Cunningham’s 2022 base salary for Mr. Cunningham:remained unchanged from 2021 at $342,505.

Name
2016
Base Salary
2017
Base Salary (1)
Percentage Increase from 2016
Mark T. Cunningham$300,000$303,0001%
______________________
(1)Represents salary effective January 1, 2017.


Annual Incentive Cash Bonus Compensation


The Board adopted the HLS Annual Incentive Plan (the “Annual Incentive Plan”) in August 2004 to motivate eligible employees to produce outstanding results, encourage growthperformance period for HEP’s 2022 annual incentive cash bonus program commenced on October 1, 2021 and superior performance, increase productivity, contribute to healthended on September 30, 2022. Target awards and safety goals, and aid in attracting and retaining key employees. The Compensation Committee oversees the administration of the Annual Incentive Plan, and any potential awards granted pursuant to the plan are subject to final determination by the Compensation Committee of achievement of the performance metrics for the applicable performance periods.

In the fourth quarter of 2016, the Compensation Committee approved target awards under the Annual Incentive Plan for 2017 based on a pre-established percentage of Mr. Cunningham’s base salary and determined that the applicable performance period for the Annual Incentive Plan awards would be the 12-month period beginning October 1, 2016 and ending September 30, 2017, with determination and payment of the2022 annual incentive cash bonus amounts occurringprogram for Mr. Cunningham were determined by the then-current President of HLS in the fourth quarter of 2017.2021.


The 2017 Annual Incentive Plan awardHistorically, HF Sinclair Shared Officers have not participated in HEP’s annual incentive cash bonus program. However, in October 2021, the Chief Executive Officer reviewed the contributions of Mr. Voliva, then President of HLS and an HF Sinclair Shared Officer, and determined that Mr. Voliva would participate in HEP’s 2022 annual incentive cash bonus program in light of his increased responsibilities for HLS and HEP in 2022 following Mr. CunninghamCunningham’s Retirement.

As Mr. Voliva was subjectan HF Sinclair Shared Officer and did not receive a separate base salary solely for his contributions to achievement ofHLS and HEP in 2022, the following metrics:

Actual Distributable Cash Flow vs. Budget: Half of theChief Executive Officer set his target award may be earned based upon our actual distributable cash flow during the performance period compared to the budgeted distributable cash flow for the performance period, adjusted for differences in estimated and actual Producers Price Index adjustments and differences in the timing of known acquisitions.

The payout on this metric is based on the following:

Actual Distributable Cash Flow vs. BudgetBonus Achievement (1)
Less than 100%Actual Distributable Cash Flow as Percentage of Budget
100%100%
Greater than 100%100% plus 3% for each 1% Actual Distributable Cash Flow exceeds Budget


_________________________
(1)The percentages are interpolated between percentage points and rounded to the nearest hundredth percent.

The performance metric of actual distributable cash flow is used because it is a widely accepted financial indicator for comparing partnership performance. We believe that this measure provides an enhanced perspective of the operating performance of our assets and the cash our business is generating, and is therefore a useful criterion in evaluating management’s performance and in linking the payout of the award to our performance.

Individual Performance: The other half of the target award may be earned based on the employee’s individual performance during the performance period, as determined in the discretion of the employee’s immediate supervisor. The employee’s individual performance is evaluated through a performance review by the employee’s immediate supervisor, which includes a written assessment. The assessment reviews several criteria, including how well the employee performed his or her pre-established individual goals during the performance period and the employee’s interpersonal effectiveness, integrity, and business conduct.

The Compensation Committee also has discretion to approve an increase or a decrease in the bonus amount an executive officer would otherwise earn. Any increases or decreases are determinedopportunity at $400,000, based on a varietytarget bonus percentage of factors, including performance with respect100% and subject to the pre-definedfinancial, operational and strategic and individual performance metricsmeasures applicable to other participants in the annual incentive cash bonus program as well as environmental, health and safety and conditions outside the controldescribed below.

Any annual incentive cash bonus compensation granted by HF Sinclair for 2022 to any of the HF Sinclair Shared Officers will be disclosed in HF Sinclair’s 2023 Proxy Statement to the extent such individuals are “named executive that could have affectedofficers” of HF Sinclair for the performance metrics. If the Compensation Committee believes additional compensation is warranted to reward an executive for outstanding performance, the Compensation Committee may increase the executive’s bonus amount in its discretion. Alternatively, poor results could, in the discretion of the Compensation Committee, result in a decrease in a bonus. In making the determination as to whether such discretion should be applied (either to decrease or increase a bonus), the Compensation Committee reviews recommendations from management.2022 fiscal year.


The following table sets forth the minimum, target and maximum award opportunities for Mr. Cunningham (as a percentage of annual base salary) forand Mr. Cunningham for 2017, and the portionVoliva (as a percentage of his $400,000 target award opportunity allocated to each performance metric. The award opportunity amountsbonus opportunity) for 2022, and allocations were not changed from 2016 for Mr. Cunningham.

 Allocation Between Performance MetricsAward Opportunities
NameActual vs. Budgeted DCFIndividualTargetMaximum
Mark T. Cunningham20.0%20.0%40.0%80.0%

Following the end of the performance period, the Chief Executive Officer evaluates the extent to which the applicable performance metrics have been achieved and recommends a bonus amount for the executive officer to the Compensation Committee. The Compensation Committee then determines the actual amount of the bonus award earned by and payable to the executive officer. Pursuant to our Annual Incentive Plan, the Compensation Committee determines actual achievement of each performance metric individually and the percentages determined with respect to the two performance metrics are then added together and multiplied by the individual’s base salary to calculate the bonus amount.

For the 2017 performance period, the actual distributable cash flow ($238.9 million) exceeded the budgeted distributable cash flow ($232.0 million) by approximately 2.9%. As a result, the payout on this metric was approximately 110% of the portion of the target award relatedopportunity that is allocated to this metric.each performance measure (as a percentage of his annual base salary for Mr. Cunningham and as a percentage of target bonus opportunity for Mr. Voliva). The target percentages for Mr. Cunningham were unchanged from the 2021 year. Mr. Voliva did not participate in the annual incentive cash bonus program in the 2021 year.

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 Award OpportunitiesAllocation Among Performance Measures
(as a percentage of annual base salary or target bonus, as applicable)
NameMinimumTargetMaximumFinancial
Measures		Operational MeasuresStrategic and Individual Measures
Mark T. Cunningham22.5%45.0%90.0%18%18%9%
Richard L. Voliva III50%100%200%40%40%20%
The financial measures are weighted equally with the operational measures. Awards are capped to avoid encouraging an excessive short-term focus, potentially at the expense of long-term performance.
To facilitate timely determination of award payouts, the measurement period for each of the above metrics covers four consecutive quarters starting with the fourth quarter of the preceding year (2021) and ending with the third quarter of the following year (2022).
These awards were subject to our achievement of specified levels of performance with respect to financial, operational and strategic and individual performance measures. The following table sets forth the various components for each measure.

Performance Measure (percentage of the annual bonus awards)
Components
(percentage of each performance measure)
How It’s Measured
(percentage of each component)
Financial (40%)EBITDACumulative EBITDA performance of HEP vs. Cumulative Target for HEP
Operational (40%)
• Environmental, Health and Safety (40%)(1)




• Reliability (35%) (2)

• Operating Expense vs. Budget (25%) (3)

• Recordable Injury Rate
• Lost Time Injuries
• Vehicle Incidents
• Employee Based Environmental Releases

• Solomon Liquid Pipeline Availability


Strategic and Individual (20%)Relevant individual metrics for each named executive officer
Mark T. Cunningham
 • Safety and environmental
 • Capital project management

Richard L. Voliva III
 • Sinclair Integration
 • Operations Success and Commercial Development
 • Cash Generation and Return to Unitholders

(1)The EHS metric is divided into the following four equally weighted measures:
•Recordable Injury Rate, which is based on the number of employees out of 100 that have been involved in a recordable event.
•Lost Time Injury, which is based on the number of injuries causing an employee to miss work.
•Vehicle Incidents, which is based on the number of incidents generating greater than $5,000 of property damage per 1,000,000 miles driven by HEP employees.
•Employee Based Environmental Releases, which is based on loss of containment caused by an employee that is reportable to either a state or federal agency.
(2)The reliability metric is based on the weighted average Solomon Liquid Pipeline Availability.
(3)Operating Expense includes all direct and controllable cash operating costs, which includes Selling, General and Administrative (SG&A) costs. Budgeted costs exclude asset write-downs, impairments, inventory valuation charges, unbudgeted litigation and legal settlement costs, environmental charges resulting from events which occurred prior to the beginning of the performance period, variable energy and utility costs, and unbudgeted bonus expenses and costs
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related to unbudgeted new capital assets brought online and acquisitions made during the period. The metric is based on the actual cash operating expense of each segment versus the budgeted cash operating expense for each segment.

Financial Measures

The table below sets forth the threshold, target and maximum performance levels for each financial measure and the actual results for the financial measures in 2022:
MetricThreshold (50%)Target
(100%)		Maximum (200%)Actual for 2022Percent of
Target Bonus
Achievement
EBITDA (in millions)$323$340$357$373200%
________________________
Payouts are interpolated between threshold and target and target and maximum.
Operational Measures

The table below sets forth the threshold, target and maximum performance levels for each operational measures and the actual results for the operational measures in 2022:
MetricThreshold (50%)Target
(100%)		(200)%Maximum (250%)Actual for
 2022		Percent of
Target Bonus
Achievement
EH&S138%
Recordable Injury Rate1.00.800.6001.210%
Lost Time Injuries21n/a01100%
Vehicle Incidents1.81.41.000.33200%
Employee Based Environmental Releases32100250%
______________________
Payouts are interpolated between thresholds and targets and target up to a 200% payout. To achieve a maximum payout, no incidents are allowed.
MetricThreshold (50%)Target (100%)Maximum (200%)Actual for 2022Percent of
Target Bonus
Achievement
Reliability98.0% Available98.75% Available≥ 99.5% Available99.65%200%
Operating Expense5% over BudgetBudget5% or more under Budget20.4% over Budget0%
_________________________
Payouts are interpolated between threshold and target and target and maximum.

The total percent of target bonus achieved for 2017the operational measures was 135%.

Strategic and Individual Performance Measures

In addition to the measures mentioned above, a portion of the awards for Messrs. Cunningham and Voliva was based on the Chief Executive Officer’s evaluation of their strategic and individual performance during the year. Messrs. Cunningham and Voliva were deemed to have achieved 100% and 110%, respectively, of their target bonus for the strategic and individual performance measures.

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2022 Performance
The following table sets forth Mr. CunninghamCunningham’s target bonus as a percentage of base salary including payments made based onand the actual distributablepayouts to Mr. Cunningham for 2022 as a percentage of base salary earned by Mr. Cunningham during the 2022 performance period. Mr. Cunningham’s 2022 annual incentive cash flow versus budgetbonus was pro-rated for the portion of the 2022 performance period he served as an employee prior to his Retirement. The table below sets forth Mr. Voliva’s target bonus as a percentage of the $400,000 target bonus opportunity set by the Chief Executive Officer in October 2021 and discretionary bonuses awarded for individual performance.

NameActual vs. Budgeted DCFIndividualTotal
Mark T. Cunningham22.0%20.0%42.0%
the actual payouts Mr. Voliva received pursuant to his Separation Agreement (as defined below) as a percentage of his target bonus opportunity, using estimates in effect at the time of his separation.
 
Name
Target
Bonus
Financial
Measures
  
Operational Measures
Strategic and Individual Measures
Percentage of
Base Salary
Earned
Percentage of
Target Bonus
Earned
Mark T. Cunningham45%61%61%30%69%152%
Richard L. Voliva III100%60%60%30%N/A150%


Long-Term Equity Incentive Compensation


The Long-Term Incentive Plan was adopted by the Board in August 2004 with the objective of:


•promoting our interests by providing equity incentive compensation awards to eligible individuals,individuals;


•enhancing our ability to attract and retain the services of individuals who are essential for our growth and profitability,profitability;


•encouraging those individuals to devote their best efforts to advancing our business,business; and




•aligning the interests of those individuals with the interests of our unitholders.


In determining the appropriate amount and type of long-term equity incentive awards to be granted each year, the Compensation Committee and the Board consider the executive’s position, scope of responsibility, base salary and available compensation information for executives in comparable positions in similar companies. Our goal is to reward the creation of value and strong performance with variable compensation dependent on that performance.

The Compensation Committee and the Board typically grantsgrant long-term equity incentive awards to dedicated HLS officers on an annual basis. The Compensation Committee makes annualAnnual long-term equity incentive award grants are made in the fourth quarter of the year preceding the year to which the award relates, in order to align the timing of the long-term equity incentive award grants with the timing of the other compensation decisions made for the dedicated HLS officers. AsHowever, due to Mr. Cunningham’s planned Retirement, management did not recommend, and the Board did not grant, a result, annual long-term equity incentive awardsaward to Mr. Cunningham in October 2021 for the 2017 year were2022 year.

In connection with Mr. Cunningham’s Retirement, (i) 2,092 phantom units granted under his 2019 and 2020 phantom unit awards vested on a pro rata basis in October 2016an amount attributable to the individuals whoportion of the service period Mr. Cunningham completed during the applicable vesting period and the remainder of the unvested phantom unit awards were dedicated HLS officers at that time. Pursuantforfeited and (ii) 10,889 performance units granted under his 2019 and 2020 performance unit awards vested on a pro rata basis in an amount attributable to SEC rules, the long-term equity incentiveportion of the service period Mr. Cunningham completed during the applicable vesting period multiplied by the target number of performance units awarded and the remainder of the unvested 2019 and 2020 performance unit awards grantedwere forfeited. His vested phantom unit and performance unit awards settled six months following his Retirement Date (as defined below) as Mr. Cunningham was subject to certain executive officer level deferral requirements imposed by Section 409A of the Code. The terms of Mr. Cunningham’s 2019 and 2020 phantom unit and performance unit awards were previously disclosed in October 2016Part III of our Annual Report on Form 10-K for the 2017 year are disclosed as 2016 compensation in the Summary Compensation Table (with respect to those Named Executive Officers who received long-term equity incentive awards from us in October 2016periods ending December 31, 2019 and who were Named Executive Officers for 2016) and are not included in the 2017 Grants of Plan-Based Awards table; however, because these awards relate to the 2017 year, they are described in greater detail below.December 31, 2020, respectively.


In determining the appropriate amount and type of long-term equity incentive awards to be granted each year, the Compensation Committee considers the executive’s position, scope of responsibility, base salary and available compensation information for executives in comparable positions in similar companies. Our goal is to reward the creation of value and strong performance with variable compensation dependent on that performance.

For the 2017 year, the Compensation Committee awarded both restricted units and performance units to Mr. Cunningham. It is generally our practice not to make long-term equity incentive award grants to the HFCHF Sinclair Shared Officers. Any equity compensation awards granted by HFCHF Sinclair for 20172022 to any of the HFCHF Sinclair Shared Officers will be disclosed in HFC’s 2018HF Sinclair’s 2023 Proxy Statement.

Restricted Unit Awards

In October 2016, Mr. Cunningham was granted restricted units. The number of restricted units awarded is initially approved by the Compensation Committee in dollar amounts established accordingStatement to the pay gradeextent such individuals are “named executive officers” of the executive officer. The award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award. The following table sets forth the number of restricted units awarded to Mr. Cunningham in October 2016HF Sinclair for the 2017 year:2022 year.


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NameNumber of Restricted Units
Mark T. Cunningham   4,128
Restricted unitholders have all the rights of a unitholder with respect to the restricted units, including the right to receive all distributions paid with respect to such restricted units (at the same rate as distributions paid on our common units) and any right to vote with respect to the restricted units, subject to limitations on transfer and disposition of the units during the restricted period. The distributions are not subject to forfeiture.

The restricted units granted in October 2016 vest in three equal annual installments as noted in the following table and will be fully vested and nonforfeitable after December 15, 2019.

A
Restricted Unit Vesting Criteria
Vesting Date (1)
Cumulative Amount of Restricted Units Vested
Immediately following December 15, 20171/3
Immediately following December 15, 20182/3
Immediately following December 15, 2019All

(1) Vesting will occur on the first business day following December 15 if December 15 falls on a Saturday or a Sunday. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described in greater detail below in the section titled “Potential Payments upon Termination and Change in Control.”

Performance Unit Awards

A performance unit is a notational phantom unit that entitles the grantee to receive a common unit upon the attainment of pre-established performance targets over a specified performance period, which may include the achievement of specified financial objectives determined by the Compensation Committee, and satisfaction of certain continued service conditions.



In October 2016, Mr. Cunningham was granted performance units with a performance period that began on January 1, 2017 and ends on December 31, 2019. An executive officer generally must remain employed through the end of the performance period to be eligible to earn any of the performance units. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described below in the section titled “Potential Payments upon Termination and Change in Control.”

With respect to the performance unit awards for the 2017 year, Mr. Cunningham was granted a target number of performance units. The target number is initially approved by the Compensation Committee in dollar amounts established according to the pay grade of the executive officer. The target award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award. The following table sets forth the target number of performance units granted to Mr. Cunningham in October 2016 for the 2017 year:

NameTarget Number of Performance Units
Mark T. Cunningham4,128


The Compensation Committee determined that the increase in distributable cash flow per common unit during the performance period should be used as the performance objective for the performance unit awards granted in October 2016. The actual number of units earned at the end of the performance period is based on the “Achieved Distributable Cash Flow/Unit” as compared to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” Specifically, the actual number of units earned at the end of the performance period will be determined by multiplying the target number of performance units awarded by the applicable performance percentage as follows:

Achieved Distributable Cash Flow/Unit EqualsPerformance Percentage (%) (1)
Base Distributable Cash Flow/Unit or Less50%
Target Distributable Cash Flow/Unit100%
Incentive Distributable Cash Flow/Unit150%
____________________
(1)The percentages above are interpolated between points up to a maximum of 150% but no less than 50%. The result is rounded to the nearest whole percentage, but not to a number in excess of 150%.



For the performance units:

TermWhat It Means
Achieved Distributable Cash Flow/UnitActual Distributable Cash Flow in 2019 adjusted, on an annualized basis, to the extent such adjustment is not reflected in Actual Distributable Cash Flow in 2019, to include the effect of the closing of any acquisition to income and/or outstanding HEP common units and/or to eliminate any general partner give-back and any other aberrational event, as determined by the Compensation Committee, divided by the number of common units outstanding as of year-end 2019
Base Distributable Cash Flow/UnitActual Distributable Cash Flow for 2016 adjusted, on an annualized basis, to include the effect of the closing of any acquisition to income and/or outstanding HEP common units and/or to eliminate any general partner give-back and any other aberrational event, as determined by the Compensation Committee, divided by the number of common units outstanding as of year-end 2016
Target Distributable Cash Flow/Unit
Base Distributable Cash Flow/Unit x (100% + WAIA1) x (100% + WAIA2) x (100% + WAIA3)
Incentive Distributable Cash Flow/Unit
Base Distributable Cash Flow/Unit x (100% + (WAIA1 + 4%)) x (100% + (WAIA2 + 4%)) x (100% + (WAIA3 + 4%))
WAIA
The weighted after inflation adjustment for each of years 1, 2 and 3 of the performance period (identified as WAIA1, WAIA2, and WAIA3, respectively) to HEP’s applicable sources of revenue calculated as follows: annual percentage increase of the Producers Price Index - Commodities-Finished Goods published by the U.S. Department of Labor, Bureau of Labor Statistics

For purposes of calculating Target Distributable Cash Flow/Unit and Incentive Distributable Cash Flow/Unit, the WAIA is rounded to the nearest 0.1%

Prior to vesting, distributions are paid on each outstanding performance unit, based on the target number of performance units subject to the award, at the same rate as distributions paid on our common units. The distributions are not subject to forfeiture.

On October 18, 2017, we entered into an equity restructuring agreement (the “Equity Restructuring Agreement”) with our general partner HEP Logistics pursuant to which the incentive distribution rights held by HEP Logistics were cancelled and the 2% general partner interest held by HEP Logistics was converted into a non-economic general partner interest (together, the “GP/IDR Restructuring”). In consideration for the GP/IDR Restructuring, we issued to HEP Logistics 37,250,000 common units, and HEP Logistics agreed to forgo $2.5 million in distributions per quarter for 12 consecutive quarters (for an aggregate of $30 million) beginning with the first quarter in which units issued as consideration for the GP/IDR Restructuring are eligible to receive distributions.

Because the performance unit payouts are based on growth in Distributable Cash Flow per Unit, the GP/IDR Restructuring would have substantially increased the unit count, which would have reduced the Distributable Cash Flow per Unit and thus impacted performance unit payouts notwithstanding performance. Accordingly, in conjunction with the GP/IDR Restructuring, we retroactively adjusted the historical unit count (for purposes of calculating Base Distributable Cash Flow/Unit) by the amount of units issued in conjunction with the GP/IDR Restructuring to reset the “reference period” distributable cash flow per unit and remove any impact of the GP/IDR Restructuring on performance unit payouts.

Acquisition of Common Units for Long-Term Incentive Plan Awards


Common units delivered in connection with long-term equity incentive awards may be common units acquired by HLS on the open market, common units already owned by HLS, common units acquired by HLS directly from us or any other person or any combination of the foregoing. We currently do not hold treasury units. HLS is entitled to reimbursement by us for the cost of acquiring the common units utilized for the grant or settlement of long-term equity incentive awards.




Retirement and Other Benefits


Our Named Executive Officers participate in certain retirement plans sponsored and maintained by HFC.HF Sinclair. The cost of retirement benefits for dedicated HLS officers areis charged monthly to us in accordance with the terms of the Omnibus Agreement. The terms of these benefit arrangements are described below.


Defined Contribution Plan


For 2017,2022, Mr. Cunningham was eligible to participate in the HollyFrontierHF Sinclair Corporation 401(k) Retirement Savings Plan, a tax qualified defined contribution plan (the “401(k) Plan”). Employees who are not eligible to participate in the NQDC Plan may contribute amounts between 0% and 75% of their eligible compensation to the 401(k) Plan, while employees who participate in the NQDC Plan may contribute amounts between 0% and 50% of their eligible compensation to the 401(k) Plan. Employee contributions that were made on a tax-deferred basis were generally limited to $18,000$20,500 for 2016,2022, with employees 50 years of age or over able to make additional tax-deferred contributions of $6,000.$6,500.


For 2017,2022, all employees received an employer retirement contribution to the 401(k) Plan of 3% to 8% of the participating employee’s eligible compensation under the 401(k) Plan, subject to applicable Internal Revenue Code limitations, based on years of service, as follows:
Years of Service
Retirement Contribution

(as percentage of eligible compensation)
Less than 5 years3%
5 to 10 years4%
10 to 15 years5.25%
15 to 20 years6.5%
20 years and over8%


In addition to the retirement contribution, in 2017,2022, employees received employer matching contributions to the 401(k) Plan equal to 100% of the first 6% of the employee’s eligible compensation contributed to the 401(k) plan up to compensation limits. Matching contributions vest immediately, and retirement contributions are subject to a three-year cliff-vesting period.


The 401(k) Plan benefits for Mr. Cunningham were charged to us in 20172022 pursuant to the Omnibus Agreement.


Deferred Compensation Plan


In 2017,2022, Mr. Cunningham was eligible to participate in the NQDC Plan. The NQDC Plan provides certain management and other highly compensated employees an opportunity to defer compensation in excess of qualified retirement plan limitations on a pre-tax basis and accumulate tax-deferred earnings to achieve their financial goals.


Participants in the NQDC Plan can contribute between 1% and 50% of their eligible earnings, which includes base salary and bonuses, to the NQDC Plan. Participants in the NQDC Plan may also receive certain employer-provided contributions, including, for 2017, matching restoration contributions, retirement restoration contributions, and nonqualified nonelective contributions. Matching restoration contributions and retirement restoration contributions represent contribution amounts that could not be made under the 401(k) Plan due to Internal Revenue Code limitations on tax-qualified plans. Participants in the NQDC Plan are entitled to make independent deferral elections to the NQDC Plan and the 401(k) Plan, regardless of whether the individual has met the contribution limitations under the 401(k) Plan. See the narrative preceding the “Nonqualified Deferred Compensation Table” for additional information regarding these contributions and the other terms and conditions of the NQDC Plan.


The NQDC Plan benefits for Mr. Cunningham were charged to us in 20172022 pursuant to the Omnibus Agreement.


Retirement Pension Plans
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HFC traditionally maintained the Holly Retirement Plan, a tax-qualified defined benefit retirement plan
(the “Retirement Plan”), and the Holly Retirement Restoration Plan, an unfunded plan that provides additional payments to participating executives whose Retirement Plan benefits were subject to certain Internal Revenue Code limitations (the “Restoration Plan”). The Retirement Plan was liquidated in its entirety in June 2013. HFC continues to maintain the Restoration Plan, but all participants in that plan ceased accruing additional benefits as of May 1, 2012.



Mr. Cunningham is the only Named Executive Officer who previously participated in the Retirement Plan. None of our Named Executive Officers ever participated in the Restoration Plan.

Other Benefits and Perquisites


Our Named Executive Officers are eligible to participate in the same health and welfare benefit plans, including medical, dental, life insurance, and disability programs sponsored and maintained by HFC,HF Sinclair, that are generally made available to all full-time employees of HFC.HF Sinclair. Health and welfare benefits for Mr. Cunningham were charged to us in 20172022 pursuant to the Omnibus Agreement. In August 2022, Mr. Cunningham received a retiree health contribution of $25,645, representing 50% of his COBRA rate for the high deductible health plan/no health savings account option for the tier of coverage in effect under the HF Sinclair medical plan at the time of his Retirement multiplied by 36. As a highly compensated employee, payment of Mr. Cunningham's contribution was deferred pursuant to Section 409A of the Code and paid to him in a lump sum cash payment


It is the Compensation Committee’s policy to provide only limited perquisites to our Named Executive Officers. We provided a reserved parking space for Mr. Cunningham in 2017.2022. In addition, we may also reimburse our executive officers for limited entertainment expenses that we deem to serve a business purpose and provide personal benefits to our executive officers in limited circumstances associated with executive team-building and strategy planning events.


Change in Control Agreements


Neither we nor HLS has entered into any employment agreements with any of the Named Executive Officers. On February 14, 2011, the Board adopted the Holly Energy Partners, L.P. Change in Control Policy (the “Change in Control Policy”) and the related form of Change in Control Agreement for certain officers of HLS (each, a “Change in Control Agreement”). The Change in Control Agreements contain “double-trigger” payment provisions that require not only a change in control of HFC,HF Sinclair, HLS or HEP, but also a qualifying termination of the executive’s employment within a specified period of time following the change in control in order for an officer to be entitled to benefits. We believe the Change in Control Agreements provide for management continuity in the event of a change in control and provide competitive benefits for the recruitment and retention of executives.


We entered into a Change in Control Agreement with Mr. Voliva, effective as of April 28, 2014, and Mr. Cunningham, effective as of February 14, 2011, in accordance with the Change in Control Policy. The Change in Control Agreement with Mr. Voliva was terminated effective October 31, 2016 when Mr. Voliva entered into a Change in Control Agreement with HFC.HF Sinclair. The material terms and the quantification of the potential amounts payable under the Change in Control Agreement in effect with Mr. Cunningham in 2017 are described below in the section titled “Potential Payments upon Termination or Change in Control.” We bear all costs and expenses associated with this agreement.was terminated effective February 18, 2022 when Mr. Cunningham retired.


HFC hasHF Sinclair entered into Change in Control Agreements with Messrs. Damiris andJennings, Voliva and Harrison and Ms. McWatters,Bhatia, which were in effect during 20172022 and the costs of which are fully borne by HFCHF Sinclair (the “HFC“HF Sinclair Change in Control Agreements”). Payments and benefits under the HFCHF Sinclair Change in Control Agreements are triggered only upon a change in control of HFC.HF Sinclair. The HF Sinclair Change in Control Agreement with Mr. Voliva was terminated effective September 15, 2022 when Mr. Voliva separated. The material terms, and the qualification, of the potential amounts payable under the HFCHF Sinclair Change in Control Agreements with Messrs. Damiris and VolivaMr. Jennings and Ms. McWattersBhatia will be described in HFC’s 2018HF Sinclair’s 2023 Proxy Statement.

Severance Pay Plan

On October 25, 2022, the Board adopted the Severance Pay Plan pursuant to which members of senior management or other executives whose services are solely dedicated to HLS, as designated by HLS, will be eligible to receive the severance benefits provided for under the Severance Pay Plan, pursuant to the terms and conditions of the Severance Pay Plan and the individual participation agreements which will specify the terms and conditions for each eligible participant and shall govern to the extent such terms vary from the Severance Pay Plan. The Severance Pay Plan was not applicable to any Named Executive Officers during the 2022 year, although we are including a description of the potential benefits that we put in place for future dedicated HLS Named Executive Officers. HF Sinclair has its own severance pay plan applicable to HF Sinclair Shared Officers, which will be disclosed in HF Sinclair's 2023 Proxy Statement, as applicable.

Unless otherwise specified in an individual participation agreement, upon a termination without Cause (as defined below) by HLS, the participant will be eligible to receive the following benefits:

•a cash payment, payable in 12 monthly installments, equal to a percentage of such participant’s annual base salary, plus the amount of bonus, if any, that would have been paid under the annual cash incentive compensation program (paid as if HLS had achieved target level of performance for the year of the participant’s termination); and

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•continuation coverage for the individual and his or her eligible dependents under our group health plans pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended, for twelve months at active employee rates, unless such coverage is earlier terminated in accordance with the terms of the Severance Pay Plan.

The applicable percentage of annual base salary and bonus (if any) will be determined based on the officer’s pay grade classification in accordance with the following chart:

E3 (CEO)200% + 100% target bonus
E1, E2100% + 100% target bonus
M5100%

Pursuant to the Severance Pay Plan, a termination for “Cause” means (a) an act or acts of dishonesty by a participant constituting a felony or serious misdemeanor and resulting or intended to result directly in gain or personal enrichment at the expense of HLS or any subsidiary; (b) gross or willful and wanton negligence in the performance of a participant’s material and substantial duties of employment with HLS and its subsidiaries; or (c) a participant’s conviction of a felony involving moral turpitude. The existence of Cause shall be determined by HLS, in its sole and absolute discretion.

Unit Ownership and Retention Policy for Executives


The Board, the Compensation Committee and our executive officers recognize that ownership of our common units is an effective means by which to align the interests of our officers with those of our unitholders. In October 2013,The dedicated HLS officers are subject to the Compensation Committee recommended, and the Board approved, a newHEP unit ownership and retention policy for dedicated HLS officers. During 2017, thepolicy. The unit retention requirement for Mr. Cunningham prior to his Retirement was as follows:


Executive OfficerValue of Units
Mark T. Cunningham1x Base Salary


Each covered officer is required to meet the applicable requirements within five years of first being subject to the policy.Officers are required to continuously own sufficient units to meet the unit ownership and retention requirements once attained. Until the officers attain compliance with the unit ownership and retention policy, the officers will be required to hold 25% of the units received from any equity award, net of any units used to pay the exercise price or tax withholdings. If an officer attains compliance with the unit ownership and retention policy and subsequently falls below the requirement because of a decrease in the price of our common units, the officer will be deemed in compliance provided that the officer retains the units then held.


As of December 31, 2017,his Retirement Date, Mr. Cunningham was in compliance with the HEP unit ownership and retention policy. As of December 31, 2022, there were no Named Executive Officers subject to the HEP unit ownershipand retention policy.




Anti-Hedging and Anti-Pledging Policy


OurAll of our employees, including our Named Executive Officers, are subject to the HEPour Insider Trading Policy, which, among other things, prohibits such individualsemployees from entering into short sales or hedging or pledging shares of our common units and HFCHF Sinclair common stock. The anti-hedging policy contained in our Insider Trading Policy specifically prohibits employees, including our named executive officers, and their designees from purchasing financial instruments or otherwise engaging in transactions that hedge or offset or are designed to hedge or offset any decrease in the market value of HEP or HF Sinclair securities (or derivatives thereof), including through, among other mechanisms, the purchase of financial instruments (such as prepaid variable forward contracts, equity swaps, collars, and exchange funds) or other transactions that are designed to hedge or offset any decrease in the market value of our securities. Additionally, all employees, including our named executive officers, are prohibited from holding our securities in a margin account or otherwise pledging our securities as collateral for a loan.


Tax and Accounting Implications


We account for equity compensation expenses under the rules of FASB ASC Topic 718, which requires us to estimate and record an expense for each award of equity compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued. Because we are a partnership, Section 162(m) of the Code generally does not apply to compensation paid to our Named Executive Officers for services provided to us. Accordingly, the Compensation Committee does not consider its impact in determining compensation levels. The Compensation Committee has taken
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into account the tax implications to us in its decision to grant long-term equity incentive compensation awards in the form of restrictedphantom units and performance units as opposed to options or unit appreciation rights.


Recoupment of Compensation


To date,In October 2021, the Board has not adopted arevised its formal clawback policy originally adopted by the Board in 2018 (the “Clawback Policy”) to recoup incentive basedexpand the applicability of the policy to former employees who are determined to have engaged in conduct in violation of the policy during their employment and to add a misconduct prong permitting the clawback of compensation for employees and former employees who are determined to have engaged in Misconduct (as defined below). The Clawback Policy provides that upon the occurrence of a material restatement of our financial statements (other than due to a change in accounting policy or applicable law) or upon certain acts of Misconduct, the Board may recover bonus and other incentive and equity based compensation (the “Incentive Compensation”) awarded to Board appointed officers of HLS and our subsidiaries. The Clawback Policy applies to both current and former employees who are Board appointed officers of HLS and our subsidiaries; provided, however, that the Clawback Policy only applies to Incentive Compensation awarded on or after November 1, 2021 for Board appointed officers who are former employees.

In the case of a material restatement of our financial statements (other than due to a change in accounting policy or applicable law), the Board may recover Incentive Compensation that was paid or awarded during the 24-month period preceding the restatement from such officers. In the event of such material restatement, if the Incentive Compensation would have been lower had it been calculated based on such restated results, the Compensation Committee may (as determined in its sole discretion and to the extent permitted by governing law and as appropriate under the circumstances) seek to recover for our benefit all or a portion of such Incentive Compensation awarded to any covered employee. In determining whether to seek recovery, the Compensation Committee may take into account any considerations as it deems appropriate, including whether the error was caused by intentional misconduct or other specified events. However,fraud. The amount of any recovery and the source of such recovery (whether from unvested equity compensation or future compensation payable to the covered employee) will be determined in the sole discretion of the Compensation Committee.

In any instance in which a current Board appointed officer of HLS or our subsidiaries or a former Board appointed officer employed by HLS or our subsidiaries at any point during the twelve-month period preceding the date the Compensation Committee is notified of an event of Misconduct, which is defined to include any of the following acts or events (each an act of “Misconduct”):

•an act or acts of dishonesty constituting a felony or serious misdemeanor and resulting or intended to result directly in gain or personal enrichment at the expense of HLS, HEP or any of its subsidiaries;
•gross or willful and wanton negligence in the performance of such officer’s material and substantial duties of employment with HLS, HEP and its subsidiaries; or
•conviction of a felony involving moral turpitude;

the Compensation Committee may (as determined in its sole discretion and to the extent permitted by governing law and as appropriate under the circumstances) cause HLS to (a) seek recovery of Incentive Compensation that such officer was awarded or vested within the prior 24-month period or at any time during or following the Misconduct and/or (b) cancel such officer’s unvested, unearned or unsettled Incentive Compensation without consideration; provided, however, that recoupment of Incentive Compensation from former employees only applies to Incentive Compensation awarded on or after November 1, 2021.

Additionally, equity awards granted to Named Executive Officers are subject to the terms of the Long-Term Incentive Plan, which states that such awards may be cancelled, repurchased and/or recouped to the extent required by applicable law or any clawback policy that we adopt. In addition, the award agreements for our outstanding long-term incentive compensation awards granted since October 2015 state that the award and amounts paid or realized with respect to the award may be subject to reduction, cancellation, forfeiture or recoupment to the extent required by applicable law or any clawback policy that we adopt. The Compensation Committee is reviewing the SEC’s proposed rules on incentive compensation clawbacks pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act and evaluating the practical, administrative and other implications of adopting, implementing and enforcing a clawback policy, and intends to implement a more specific clawback policy once the SEC’s rules are finalized.

2018 Compensation Decisions

Long-Term Equity Incentive Compensation

In November 2017, the Compensation Committee approved annual grants of phantom units and performance units for Mr. Cunningham. Pursuant to SEC rules, the long-term equity incentive awards granted in November 2017 for the 2018 year are disclosed as 2017 compensation in the Summary Compensation Table and are reported in the 2017 Grants of Plan-Based Awards table below. These awards are also described in greater detail in the narrative that follows.

Phantom Unit Awards

In November 2017, Mr. Cunninghamwas granted phantom units. The number of phantom units awarded is initially approved by the Compensation Committee in dollar amounts established according to the pay grade of the executive officer. The award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award. The following table sets forth the number of phantom units awarded to Mr. Cunningham in November 2017 for the 2018 year:

NameNumber of Restricted Units
Mark T. Cunningham3,861


Phantom unitholders have the right to receive distribution equivalents and other distributions paid with respect to such phantom units, and these distribution equivalents are paid at approximately the same time as distributions are paid on our common units. The distribution equivalents are not subject to forfeiture.

The phantom units granted in November 2017 to Mr. Cunningham vest in three equal annual installments as noted in the following table and will be fully vested and nonforfeitable after December 15, 2020.



Phantom Unit Vesting Criteria
Vesting Date (1)
Cumulative Amount of Restricted Units Vested
Immediately following December 15, 20181/3
Immediately following December 15, 20192/3
Immediately following December 15, 2020All

(1) Vesting will occur on the first business day following December 15 if December 15 falls on a Saturday or a Sunday. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described in greater detail below in the section titled “Potential Payments upon Termination and Change in Control.”

Performance Unit Awards

In November 2017, Mr. Cunningham was granted performance units with a performance period that began on January 1, 2018 and ends on December 31, 2020. The target number of performance units granted to Mr. Cunningham was determined in the same manner as the October 2016 performance unit awards described above. The following table sets forth the target number of performance units granted to Mr. Cunningham in November 2017 for the 2018 year:

NameTarget Number of Performance Units
Mark T. Cunningham3,861


The Compensation Committee determined that the increase in distributable cash flow per common unit during the performance period should be used as the performance objective for the performance unit awards granted in November 2017, which is the same performance objective utilized for the October 2016 awards. The actual number of units earned at the end of the performance period is based on the “Achieved Distributable Cash Flow/Unit” as compared to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” The actual number of units earned at the end of the performance period will be calculated in the same manner as the performance unit awards granted in October 2016, as adjusted to reflect the applicable performance period for the 2018 awards.

Prior to vesting, distributions are paid on each outstanding performance unit, based on the target number of performance units subject to the award, at the same rate as distributions paid on our common units. The distributions are not subject to forfeiture.


Compensation Committee Report
    
The Compensation Committee of the Holly Logistic Services, L.L.C. Board of Directors has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.


Members of the Compensation Committee:
Christine B. LaFollette, Chairperson
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Michael C. Jennings Chairman
George J. Damiris
James H. Lee

Mark A. Petersen



Executive Compensation Tables


The following executive compensation tables and related information are intended to be read together with the more detailed disclosure regarding our executive compensation program presented under the caption “Compensation Discussion and Analysis.”


Summary Compensation Table


The table below summarizes the total compensation paid or earned by each of the Named Executive Officers for the years specified to the extent such compensation is allocable to us pursuant to SEC rules.


Name and Principal PositionYearSalaryUnit Awards (1)Non-Equity
Incentive Plan Compensation (2)		All Other Compensation (3)Total
Michael C. Jennings
Chief Executive Officer and President (4)
2022$1,250,000 $— $2,200,326 $— $3,450,326 
20211,084,154 — 1,210,579 — 2,294,733 
20201,148,308 — 380,911 — 1,529,219 
John Harrison
Senior Vice President, Chief Financial Officer and Treasurer (5)
2022$310,923 $— $3,817 $— $314,740 
2021272,373 — — — 272,373 
2020219,362 — — — 219,362 
Vaishali S. Bhatia
Senior Vice President, General Counsel and Secretary (4)
2022$540,000 $— $261,278 $— $801,278 
2021476,567 $— 129,149 — 605,716 
2020403,077 — 8,364 — 411,441 
Mark T. Cunningham
Former Senior Vice President, Operations and Engineering
2022$52,729 $— $92,121 $550,603 $695,453 
2021343,791 — 247,083 73,660 664,534 
2020336,066 332,449 187,697 65,898 922,110 
Richard L. Voliva III
Former President (4)
2022$572,378 $— $713,965 $— $1,286,343 
2021697,604 — 463,122 — 1,160,726 
2020680,192 650,010 366,219 — 1,696,421 
Name and Principal Position (1)YearSalaryBonus (2)Unit Awards (3)
Non-Equity
Incentive Plan Compensation (4)
All Other Compensation (5)Total
George J. Damiris
Chief Executive Officer and President (6)
2017$1,100,000—
—
$881,430
—
$1,981,430
2016452,187—
—
—
—
452,187
Richard L. Voliva III
Executive Vice President and Chief Financial Officer (6)
2017$468,750—
—
$154,568
—
$623,318
2016255,288$193,130
$776,079
56,870
$45,225
1,326,592
2015199,338$90,000
$275,048
—
$25,838
590,224
Mark T. Cunningham
Senior Vice President, Engineering and Technical Services
2017$303,000$60,600
$275,058
$66,660
$48,692
$754,010
2016300,00060,000
275,172
79,800
  49,431
764,403
2015288,11295,512
325,132
62,808
  50,189
821,753
Denise C. McWatters
Senior Vice President, General Counsel and Secretary (6)
2017$500,000—
—
$103,867
—
$603,867
2016470,000—
—
93,359
—
563,359
2015430,000—
—
70,450
—
500,450


(1)Mr. Damiris was appointed President of HLS, effective as of February 1, 2017.

(2)Represents the discretionary bonus amount, if any, paid pursuant to the individual performance metric under our Annual Incentive Plan and any other bonus paid outside our Annual Incentive Plan. Other payments made under our Annual Incentive Plan are included in the “Non-Equity Incentive Plan Compensation” column.
(3)Represents the aggregate grant date fair value of awards of restricted units or phantom units and performance units made in the year indicated computed in accordance with FASB ASC Topic 718, determined without regard to forfeitures, and does not reflect the actual value that may be recognized by the executive. See Note 6(1)    Represents the aggregate grant date fair value of awards of equity awards made in the year indicated computed in accordance with FASB ASC Topic 718, determined without regard to forfeitures, and does not reflect the actual value that may be recognized by the executive. See Note 9 to our consolidated financial statements for the fiscal year ended December 31, 2017 for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

Awards for the 2016fiscal year ended December 31, 2022 for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

For Mr. Cunningham, awards for the 2021 fiscal year granted in October 20152020 are reported in the “Unit Awards” column of the Summary Compensation Table for 2015, awards for the 2017 fiscal year granted in October 2016 are reported in the “Unit Awards” column of the Summary Compensation Table for 2016, and awards for the 2018 fiscal year granted in November 2017 are reported in the “Unit Awards” column of the Summary Compensation Table for 2017, in each case,2020, in accordance with SEC rules.

With respect to performance units awarded in November 2017, the amounts in the Summary Compensation Table are based on a probable payout percentage of 100%. If the performance units granted in November 2017 are paid out at the maximum payout level of 150%, the grant date fair value of Mr. Cunningham’s performance units would $206,293. See “Compensation Discussion and Analysis - Overview of 2017 Executive Compensation Components and Decisions - Long-Term Equity Incentive Compensation - Performance Unit Awards.”

The terms of the phantom unit and performance unit awards granted in November 2017Cunningham did not receive an award for the 20182022 year due to his Retirement in February 2022.

For Mr. Voliva, the award reflected in 2020 was a grant of phantom units in recognition of his contributions to HLS for the 2020 fiscal year, including his advancement of business development opportunities and his oversight of growth projects.

(2)    Generally represents the annual incentive amount, if any, paid under our annual incentive cash bonus program. The 2022 award amounts under our annual incentive cash bonus program are described under “Compensation Discussion and Analysis - 2018 Compensation Decisions - Long-Term Equity Incentive Compensation.” For additional information on outstanding restricted unit, phantom unit and performance unit awards, see below under “Outstanding Equity Awards at Fiscal Year End.”

(4)Represents the bonus amount, if any, paid under our Annual Incentive Plan, other than with respect to the individual performance metric (which amounts are reported in the “Bonus” column). The 2017 bonus amounts under our Annual Incentive Plan are


described above in greater detail under “Compensation Discussion and Analysis-OverviewAnalysis–Overview of 20172022 Executive Compensation Components and Decisions-AnnualDecisions–Annual Incentive Cash Bonus Compensation.” See note 6Note 4 to the Summary Compensation Table for a discussion of the amounts reported as “Non-Equity Incentive Plan Compensation” with respect to Messrs. Damiris andJennings, Voliva and Harrison and Ms. McWattersBhatia for 2017.2022. Although these amounts are reported in the “Non-Equity Incentive Plan Compensation” column, they represent incentive
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compensation determined by and earned pursuant to the HF Sinclair annual incentive bonus program, with the exception of Mr. Voliva whose reported amount includes: (i) a 2022 annual incentive cash bonus of $600,000 under our annual incentive cash bonus program paid pursuant to the terms of his Separation Agreement and (ii) an allocation of compensation determined by and earned pursuant to the HF Sinclair annual incentive bonus program in the amount of $113,965. Although Mr. Voliva's annual incentive cash bonus amount was determined prior to the end of the original performance period, the amount was determined based on the estimate of what he had earned at that time, therefore, this is reported as a payment of his regular annual incentive bonus rather than as a separation payment.

(3)    For 2022, includes the compensation as described under “All Other Compensation” below.

(4)    During 2022, each of these officers split their professional time between HF Sinclair and us, and all compensation paid to the officer for 2022 was determined and paid by HF Sinclair, with the exception of the 2022 HEP annual incentive cash bonus paid by HLS to Mr. Voliva of $600,000 (which is reported in the table for Mr. Voliva under the "Non-equity Incentive Plan Compensation" column). In accordance with SEC rules, for purposes of these disclosures, a portion of the total compensation paid by HF Sinclair to these officers for 2022 is allocated to the services the officer performed for us during 2022. The allocation was made based on the assumption that each officer spent, in the aggregate, approximately the following percentage of his professional time in 2022 on our business and affairs:

(5)NameFor 2017, includes the compensation as described under “All Other Compensation” below.

(6)During 2017, each of these officers split his or her professional time between HFC and us, and all compensation paid to him or her for 2017 was determined and paid by HFC. In accordance with SEC rules, for purposes of these disclosures, a portion of the total compensation paid by HFC to these officers for 2017 is allocated to the services he or she performed for us during 2017. The allocation was made based on the assumption that each officer spent, in the aggregate, approximately the following percentage of his or her professional time in 2017 on our business and affairs:

NamePercentage of Time
George J. DamirisMichael C. Jennings 20%25%
Richard L. Voliva III20%35%
Denise C. McWattersVaishali S. Bhatia30%25%


As a result,    With the exception of the 2022 HEP annual incentive cash bonus paid to Mr. Voliva of $600,000 (which is also reported in the table for Mr. Voliva under the “Non-equity Incentive Plan Compensation” column), only the designated percentage of the total amount of compensation each officer received from HFCHF Sinclair for 20172022 has been reported in this table, and the allocated amount has been solely attributed in the table above to his or herthe officer’s base salary and non-equity incentive plan compensation. This amount represents the aggregate dollar value of total compensation paid to the officer by HFCHF Sinclair (including base salary, non-equity incentive plan compensation, equity awards and other compensation), calculated pursuant to SEC rules, multiplied by the percentage set forth next to her or herhis name above. The total compensation paid by HFCHF Sinclair to Messrs. DamirisJennings and Voliva and Ms. McWatters in 2017Bhatia (including the portion of his or hertheir salary and non-equity incentive plan compensation reported in this table), includingand a discussion of how the total amount of his or herthe officer’s non-equity incentive plan compensation for 20172022 was determined, will be disclosed in HFC’s 2018HF Sinclair’s 2023 Proxy Statement. Mr. Harrison is not expected to be a named executive officer with respect to HF Sinclair, therefore, his compensation arrangements are described in Note 5 below.
(5)    During 2022, Mr. Harrison split his professional time between HF Sinclair and us, and all compensation paid to him for 2022 was determined and paid by HF Sinclair. In accordance with SEC rules, for purposes of these disclosures, a portion of the total compensation paid by HF Sinclair to him for 2022 is allocated to the services he performed for us during 2022. The allocation was made based on the assumption that he spent, in the aggregate, approximately 25% of his professional time in 2022 on our business and affairs.

As a result, only the designated percentage of the total amount of compensation Mr. Harrison received from HF Sinclair for 2022 has been reported in this table, and the allocated amount has been solely attributed in the table above to his base salary. This amount represents the aggregate dollar value of total compensation paid to him by HF Sinclair (including base salary, bonus, non-equity incentive plan compensation, equity awards and other compensation), calculated pursuant to SEC rules, multiplied by 25%. The total compensation paid by HF Sinclair to Mr. Harrison in 2022 (including the portion of his salary reported in this table) is as follows: (i) salary of $310,923 for the entirety of 2022, (ii) a one-time discretionary bonus of $25,000 relating to a successful corporate acquisition consummated in 2022, (iii) a retention bonus of $100,000, (iv) stock awards of $347,527, which reflect the aggregate grant date fair value of awards of restricted stock units and performance share units granted by HF Sinclair to Mr. Harrison in November 2022 (2,661 restricted stock units and 2,661 performance share units (at target), based on a grant date closing price of $62.64 for HF Sinclair’s common stock), calculated in accordance with FASB ASC Topic 718, (v) a cash incentive award pursuant to the Long-Term Incentive Plan of $166,668, which vests over a three-year period in increments of one-third starting on December 1, 2023, (vi) $236,482 pursuant to HF Sinclair’s 2022 annual incentive cash compensation program, (vii) $38,125 in 401(k) plan matching contributions and retirement contributions in 2022, and (viii) $34,236 in NQDC Plan matching contributions and retirement contributions in 2022. For additional information regarding HF Sinclair’s compensation arrangements, please refer to HF Sinclair’s 2023 Proxy Statement.

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All Other Compensation
The table below describes the components of the compensation included in the “All Other Compensation” column for 20172022 in the Summary Compensation Table above.
Name (1)401(k) Plan Company Matching Contributions401(k) Plan Retirement ContributionsNQDC Plan Company Matching ContributionsNQDC Plan Retirement ContributionsTotalName (1)401(k) Plan Company Matching Contributions401(k) Plan Retirement ContributionsNQDC Plan Company Matching ContributionsNQDC Plan Retirement ContributionsOther (2)Total
George J. Damiris—
—
—
—
—
Michael C. JenningsMichael C. Jennings— — — — — — 
John HarrisonJohn Harrison— — — — — — 
Vaishali S. BhatiaVaishali S. Bhatia— — — — — — 
Mark T. CunninghamMark T. Cunningham$3,162 $3,939 $— $— $543,502 $550,603 
Richard L. Voliva III—
—
—
—
—
Richard L. Voliva III— — — — — 
Mark T. Cunningham$16,200
$13,913
$9,909
$8,670
$48,692
Denise C. McWatters—
—
—
—
—
______________
(1)The value of the perquisites provided by us to our Named Executive Officers in 2017 did not exceed $10,000 in the aggregate, and therefore, in accordance with SEC rules, are not included in the table above or described in this footnote.

(1)The value of the perquisites provided by us to our Named Executive Officers in 2022 did not exceed $10,000 in the aggregate, and therefore, in accordance with SEC rules, are not included in the table above or described in this footnote.
(2)Includes an employer retiree health contribution paid to Mr. Cunningham in cash six months following his Retirement in the amount of $25,645 and consulting services fees paid to Mr. Cunningham following his Retirement in 2022 pursuant to the terms of his Consulting Agreement in the amount of $517,857. See the section below titled "Potential Payments Upon Termination or Change in Control - Retirement & Consulting Arrangements with Mr. Cunningham" for more information.

Grants of Plan-Based Awards
The following table sets forth information about plan-based awards granted to our Named Executive Officers under our equity and non-equity incentive plans during 2017.2022. In this table, awards are abbreviated as “AICP” for the annual incentive cash awards under our Annual Incentive Plan (other than with respect to the discretionary individual performance portion of the awards, which are reported in the “Bonus” column of the Summary Compensation Table above and are not included below), as “PHUA” for phantom unit awards, and as “PUA” for performance unit awards. Messrs. Damiris and Voliva and Ms. McWatters did not receive any plan-based awards from us during 2017.annual incentive cash bonus compensation program.


The phantom unit and performance unit grants reported below for Mr. Cunningham were granted in November 2017 for the 2018 fiscal year and are reported in this table as 2017 compensation in accordance with SEC rules. These awards are described in greater detail above under “Compensation Discussion and Analysis-2018 Compensation Decisions-Long-Term Equity Incentive Compensation.” Annual long-term equity incentive awards are made once each year in the fourth quarter of the year preceding the year to which the award relates in order to align the timing of the long-term equity incentive award grants with the timing of


the other compensation decisions made for our executive officers. InHowever, none of our Named Executive Officers received equity plan-based awards from us during 2022 for the 2023 fiscal year.
TypeGrant
 Date		Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)

Estimated Future Payouts Under
Equity Incentive Plan Awards
All Other
Equity Awards		Grant
Date Fair Value
NameThresholdTargetMaximumThresholdTargetMaximum
Michael C. Jennings——————————
John Harrison——————————
Vaishali S. Bhatia——————————
Mark T. CunninghamAICP$31,122$62,244$124,488
Richard L. Voliva III (1)
AICP—$200,000$400,000$800,000—————

(1)    Represents the potential payouts for awards granted under our annual incentive cash compensation program, which were subject to achieving certain performance targets with respect to financial measures, operational measures and strategic and individual measures. Amounts reported (a) in the “Threshold” column reflect 50% of the Named Executive Officer’s target award opportunity under the annual incentive cash compensation program, which, in accordance with SEC rules, is the minimum amount payable for a certain level of performance under the award, (b) in the “Target” column reflect 100% of the Named Executive Officer’s target award opportunity under the annual long-term equity incentive cash compensation program, which is the target amount payable under the award, and (c) in the “Maximum” column reflect 200% of the Named Executive Officer’s target award opportunity under the annual incentive cash compensation program, which is the maximum amount payable under the award. If less than minimum levels of performance, as described in the “Threshold” column, are attained with respect to the financial measures, operational measures and strategic and individual measures under the annual incentive cash bonus compensation program, then 0% of the Named Executive Officer’s target award opportunity will be earned. The performance targets and target awards are described under “Compensation Discussion and Analysis–Overview of 2022 Executive Compensation Components and Decisions–Annual Incentive Cash Bonus Compensation.” Although these awards were granted in October 2016the fourth quarter of 2021, they represent the 2022 Annual Incentive Plan awards and any payouts with respect to these awards are reported in the “Non-Equity Incentive Plan Compensation” column of the
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Summary Compensation Table for 2022. Amounts paid to Messrs. Jennings, Harrison and Voliva (in addition to the 2017 fiscal year were previouslyaward reported as 2016 compensation in the table above) and Ms. Bhatia for 2022 were earned and paid pursuant to the HF Sinclair annual incentive bonus program and are not included in this Grants of Plan-Based Awards table containedtable. A full discussion and reporting of the amounts paid to Messrs. Jennings and Voliva and Ms. Bhatia will be disclosed in our Annual Report on Form 10-K forHF Sinclair’s 2023 Proxy Statement. The amount paid to Mr. Harrison is reported in Note 5 to the fiscal year ended December 31, 2016.Summary Compensation Table above.

 Type
Grant
 Date
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)

Estimated Future Payouts Under
Equity Incentive Plan Awards (2)
  
NameThresholdTargetMaximumThresholdTargetMaximum
All other
Equity Awards
(3)
Grant
Date Fair Value
(4)
George J. Damiris——————————
Richard L. Voliva (5)——————————
Mark T. CunninghamAICP $0 $60,600   $121,200     
 PUA11/01/2017   1,9313,8615,792 $137,529
 PHUA11/01/2017      3,861137,529
Denise C. McWatters——————————

(1)Represents the potential payouts for the awards under our Annual Incentive Plan, which were subject to the achievement of certain performance metrics. The performance metrics and awards are described under “Compensation Discussion and Analysis - Overview of 2017 Executive Compensation Components and Decisions - Annual Incentive Cash Bonus Compensation.” Although these awards were granted in the fourth quarter of 2016, they represent the 2017 Annual Incentive Plan awards and any payouts with respect to these awards are reported in the Summary Compensation Table for 2017. Amounts reported do not include amounts potentially payable pursuant to the discretionary individual performance portion of the award. The amount actually paid with respect to the individual performance portion of the award is reported in the “Bonus” column of the Summary Compensation Table for 2017, and the amount actually paid with respect to the portion of the award reported in this table is reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table for 2017.
(2)Represents the potential number of performance units payable under the Long-Term Incentive Plan. The number of units paid at the end of the performance period may vary from the target amount, based on our achievement of specified performance measures. The terms of the performance unit awards granted in November 2017 for the 2018 fiscal year are described above under “Compensation Discussion and Analysis - 2018 Compensation Decisions - Long-Term Equity Incentive Compensation - Performance Unit Awards.” See “Compensation Discussion and Analysis - Overview of 2018 Compensation Components and Decisions - Long-Term Equity Incentive Compensation - Performance Unit Awards.”

(3)Represents awards of phantom units. The terms of the phantom unit awards granted in November 2017 for the 2018 fiscal year are described above under “Compensation Discussion and Analysis - 2018 Compensation Decisions - Long-Term Equity Incentive Compensation - Phantom Unit Awards.”
(4)Represents the grant date fair value determined pursuant to FASB ASC Topic 718, based on a closing price of our common units of $35.62 on November 1, 2017. The value of performance units granted on November 1, 2017 reflect a probable payout percentage of 100%. See note 3 to the Summary Compensation Table for additional information regarding the aggregate probable settlement percentage calculation.


Outstanding Equity Awards at Fiscal Year End


The following table sets forth information regarding outstanding restricted units, phantom units and/or performance units held by each Named Executive Officer asAs of December 31, 2017, including awards that were granted prior to 2017. The value of these awards was calculated based on a price of $32.49 per unit, the closing price2022, none of our common units on December 29, 2017 (the last trading day in 2017). Mr. Damiris and Ms. McWatters do not holdNamed Executive Officers held any outstanding equity awards under our Long-Term Incentive Plan,Plan. A full discussion and reporting of the table below does not reflect any outstanding HFCHF Sinclair equity awards held by any of our Named Executive Officers.

Under SEC rules, the number and value of performance units reported is based on the number of units payable at the end of the performance period assuming the maximum level of performance is achieved. In this table, awards are abbreviated as “RUA” for restricted unit awards, “PHUA” for phantom unit awards and “PUA” for performance unit awards. The provisions applicable to these awards upon certain terminations of employment or a changeOfficers will be disclosed in control are described below in the section titled “Potential Payments upon Termination or Change in Control.”



NameAward TypeNumber of Units That Have Not Vested (1)Market Value of Units That Have Not Vested
Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested
(2)
Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested
George J. Damiris——
—
—
—
Richard L. Voliva IIIRUA447
$14,523  
PUA  2,012
$65,370
Mark T. CunninghamRUA4,336
$140,877
  
PHUA3,861
$125,444
  
PUA  19,112
$620,949
Denise C. McWatters——
—
—
—

(1)Includes the following restricted unit awards granted by us:
in October 2015 to Mr. Voliva (1,341, after giving effectHF Sinclair’s 2023 Proxy Statement to the forfeiture by Mr. Voliva on June 1, 2016extent such persons are “named executive officers” of 2,679 of the total 4,020 restricted units originally granted) and Mr. Cunningham (4,752), of which one third vested on December 15, 2016, one third vested on December 15, 2017 and the remaining one third vests on December 15, 2018;HF Sinclair.
in October 2016 to Mr. Cunningham (4,128), of which one third vested on December 15, 2017, one third vests on December 15, 2018 and the remaining one third vests on December 15, 2019.

Includes the following phantom unit awards granted by us:
in November 2017 to Mr. Cunningham (3,861), of which one third vests on December 15, 2018, one third vests on December 15, 2019 and the remaining one third vests on December 15, 2020.

(2)Includes the following performance unit awards granted by us (the amounts included in the parentheticals reflect the target number of performance units subject to each award):
in October 2015 to Mr. Voliva (1,341, after giving effect to the forfeiture by Mr. Voliva on June 1, 2016 of 2,679 of the total 4,020 performance units originally granted) and Mr. Cunningham (4,752), in each case, with a performance period that ends on December 31, 2018;
in October 2016 to Mr. Cunningham (4,128), with a performance period that ends on December 31, 2019; and
in November 2017 to Mr. Cunningham (3,861), with a performance period that ends on December 31, 2020.

For the performance units, the actual number of units earned at the end of the performance period is based on the “Achieved Distributable Cash Flow/Unit” as compared to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” Under the terms of the grants, each of Messrs. Voliva and Cunningham may earn from 50% to 150% of the target number of performance units granted to him. See “Compensation Discussion and Analysis - Overview of 2017 Compensation Components and Decisions - Long-Term Equity Incentive Compensation - Performance Unit Awards.”



Option Exercises and Units Vested

The following table provides information regarding the vesting in 20172022 of restrictedphantom unit andand/or performance unit awards held by the Named Executive Officers. Mr. DamirisMessrs. Jennings and Harrison and Ms. McWattersBhatia do not currently hold any equity awards under our Long-Term Incentive Plan, and they did not have any equity awards under our Long-Term Incentive Plan that vested during 2017.2022. The table below does not reflect any information regarding the vesting in 20172022 of any HFCHF Sinclair equity awards held by any of our Named Executive Officers.Officers, a full discussion and reporting of those awards will be disclosed in HF Sinclair's 2023 Proxy Statement to the extent such persons are “named executive officers” of HF Sinclair. To date, we have not granted any unit options.


The value realized from the vesting of restricted unit and phantom unit awards is generally equal to the closing price of our common units on the vesting date (or, if the vesting date is not a trading day, on the trading day immediately following the vesting date, unless provided otherwise by the applicable award agreement) multiplied by the number of units acquired on vesting. The value is calculated before payment of any applicable withholding or other income taxes.


Named Executive OfficerUnit Awards
Number of Units Acquired on VestingValue Realized on Vesting
Michael C. Jennings— — 
John Harrison— — 
Vaishali S. Bhatia— — 
Mark T. Cunningham (1)
12,981 $229,634
Richard L. Voliva III (2)
14,956 $249,616
Named Executive OfficerUnit Awards
Number of Units Acquired on VestingValue Realized on Vesting
George J. Damiris—
—
Richard L. Voliva III1,440
  $ 48,816
Mark T. Cunningham8,547 (1)
$ 279,017
Denise C. McWatters—
—


(1)Includes 3,352 units that became payable to Mr. Cunningham on February 7, 2018 upon the determination by the subcommittee of the Compensation Committee that the performance percentage applicable to the target number of 2,235 performance units granted to Mr. Cunningham in October 2014 with a performance period that ended on December 31, 2017 was 150%, which performance units are treated, in accordance with SEC rules,(1)Includes common units that became payable to Mr. Cunningham as a result of the accelerated vesting of outstanding equity awards that Mr. Cunningham held on his Retirement Date (as defined below), of which 2,092 represented phantom units and 10,889 represented performance units for which vesting was accelerated. His vested phantom unit and performance unit awards settled six months following his Retirement Date, as vesting during 2017. The value realized with respect to such award is calculated based on the closing price of our common units on the date of payment.

Pension Benefits Table
As discussed in greater detail above under “Compensation Discussion and Analysis-Overview of 2017 Executive Compensation Components and Decisions-Retirement and Other Benefits-Retirement Pension Plans,” HFC previously maintained the Retirement Plan, a tax-qualified defined benefit retirement plan, that was liquidated in 2013. Mr. Cunningham was the only Named Executive Officer who was a participant in the Retirement Plan. As part of the liquidation of the Retirement Plan, the retirement benefits owed to Mr. Cunningham were distributed in a lump sum, and Mr. Cunningham is not owed any additional benefits under the Retirement Plan.

HFC continues to maintain the Restoration Plan, which is an unfunded non-qualified plan that provides supplemental retirement benefits to participating executives whose Retirement Plan benefits were subject to certain Internal Revenue Code limitations. Asexecutive officer level deferral requirements imposed by Section 409A of May 1, 2012, all participants in the Restoration Plan ceased accruingCode.

(2)Includes common units that became payable to Mr. Voliva as a result of the accelerated vesting of an outstanding phantom unit award held by Mr. Voliva pursuant to the terms of his Separation Agreement. His vested phantom unit award settled on the eighth day following the date of execution of his Separation Agreement. See the section below titled "Potential Payments upon Termination or Change of Control - Mutual Separation Agreement with Mr. Voliva" for additional benefits. None of our Named Executive Officers has accumulated benefits under the Restoration Plan.information.



Nonqualified Deferred Compensation


In 2017,2022, all of the Named Executive Officers participated in the NQDC Plan. The NQDC Plan functionsis a nonqualified plan (i.e., not tax-qualified under Section 401 of the Code) that, in 2022, functioned as a pour-over plan, allowing key employees to defer tax on income in excess of Internal Revenue Code limits that apply under the 401(k) Plan. For 2017,2022, the annual deferral contribution limit under the 401(k) Plan was $18,000,$20,500, and the annual compensation limit was $270,000.$305,000. Deferral elections
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made by eligible employees under the NQDC Plan apply to the total amount of eligible earnings the employees want to contribute across both the 401(k) Plan and the NQDC Plan. Once eligible employees reachParticipants in the Internal Revenue Code limits on contributionsNQDC Plan are entitled to make independent deferral elections to the NQDC Plan and the 401(k) Plan prior to meeting the contribution limitations under the 401(k) Plan, contributions automatically begin being contributed to the NQDC Plan. Federal and state income taxes are generally not payable on income deferred under the NQDC Plan until funds are withdrawn.

Eligible employeesparticipants may make salary deferral contributions between 1% and 50% of eligible earnings to the NQDC Plan. Eligible earnings include base pay, bonuses and overtime, but exclude extraordinary pay such as severance, accrued vacation, equity compensation and certain other items.

Eligible participants are requiredmay make salary deferral contributions between 1% and 50% of eligible earnings to make catch-up contributions to the 401(k) Plan before any contributions will be deposited into the NQDC Plan. Eligible earnings include base pay, bonuses and overtime, but exclude extraordinary pay such as severance, accrued vacation, equity compensation and certain other items. For 2017,2022, the catch-up contribution limit was $6,000.$6,500. Deferral elections


are irrevocable for an entire plan year and must be made prior to December 31 of the year immediately preceding the plan year. Elections will carry over to the next plan year unless changed or otherwise revoked.


Participants in the NQDC Plan are eligible to receive a matching restoration contribution with respect to their elective deferrals made up to 6% of the participant’s eligible earnings for the plan year in excess of the limits under Section 401(k) of the Internal Revenue Code. These matching restoration contributions are fully vested at all times. In addition, participants are eligible for a retirement restoration contribution ranging from 3% to 8% of the participant’s eligible earnings for the plan year in excess of the limits under Section 401(k) of the Internal Revenue Code, based on years of service, as follows:


Years of Services
Retirement Contribution

(as percentage of eligible compensation)
Less than 5 years3%
5 to 10 years4%
10 to 15 years5.25%
15 to 20 years6.5%
20 years and over8%


Retirement restoration contributions are subject to a three-year cliff vesting period and will become fully vested in the event of the participant’s death or a change in control. Participants may also receive nonqualified nonelective contributions under the NQDC Plan, which contributions may be subject to a vesting schedule determined at the time the contributions are made.


Participating employees have full discretion over how their contributions to the NQDC Plan are invested among the offered investment options, and earnings on amounts contributed to the NQDC Plan are calculated in the same manner and at the same rate as earnings on actual investments. Neither HLS nor HFCHF Sinclair subsidizes a participant’s earnings under the NQDC Plan. During 2017,2022, the investment options offered under the NQDC Plan were the same as the investment options available to participants in the tax-qualified 401(k) Plan. Plan, except as follows:

•the 401(k) Plan offers the TRP Target Date Retirement Fund for 2065, JP Morgan MCG, MFS Institutional International Equity, Mid Cap Value R1 Fund, Principal Stable Value Z Fund, Wilmington Emerging Markets R1 Fund, Principal Self-Directed Brokerage Account, and the stock of HF Sinclair and BP PLC; and

•the NQDC Plan instead offers the Invesco Oppenheimer International Growth R6 Fund, American Century Mid-Cap Value I Fund, Hartford SmallCap Growth Y Fund and Vanguard Federal Money Market Investor Fund.

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The following table lists the investment options for the NQDC Plan in 20172022 with the 2022 annual rate of return for each fund:



Investment FundsRate of Return
AllianzGI NFJ Small Cap Value I Fund10.02%
American Century Mid-Cap Value I Fund11.79%(1.22)%
Fidelity Contrafund32.26%(28.26)%
Harbor Capital Appreciation Inst Fund36.59%(37.72)%
Hartford SmallCap Growth Y Fund20.06%(28.82)%
Invesco Developing Markets R6 Fund(24.85)%
Invesco Oppenheimer International Growth R6 Fund(27.00)%
PIMCO Total Return Instl Fund(14.09)%
Principal LargeCap S&P 500 Index Inst Fund21.65%(18.23)%
Principal MidCap S&P 400 Index Inst Fund15.96%(13.22)%
Oppenheimer Developing Markets Institutional Fund35.33%
Oppenheimer International Growth Institutional Fund27.15%
PIMCO Total Return Instl Fund5.13%
Principal SmallCap S&P 600 Index Inst Fund13.01%(16.36)%
T. Rowe Price Retirement 2005 Fund10.67%(13.66)%
T. Rowe Price Retirement 2010 Fund11.66%(14.00)%
T. Rowe Price Retirement 2015 Fund13.34%(14.17)%
T. Rowe Price Retirement 2020 Fund15.74%(14.66)%
T. Rowe Price Retirement 2025 Fund17.68%(15.67)%
T. Rowe Price Retirement 2030 Fund19.45%(16.98)%
T. Rowe Price Retirement 2035 Fund20.88%(18.04)%
T. Rowe Price Retirement 2040 Fund22.02%(18.86)%
T. Rowe Price Retirement 2045 Fund22.41%(19.11)%
T. Rowe Price Retirement 2050 Fund22.38%(19.17)%
T. Rowe Price Retirement 2055 Fund22.33%(19.24)%
T. Rowe Price Retirement 2060 Fund22.29%(19.28)%
Vanguard Equity-Income Adm. Fund18.49%0.00%
Vanguard Federal Money Market Investor Fund0.81%1.55%
Vanguard Total Bond Market Index Institutional Fund3.57%(13.15)%
Vanguard Total International Stock Index Institutional Fund27.55%
Victory Munder Mid-Cap Core Growth R6 Fund24.73%(15.98)%


Benefits under the NQDC Plan may be distributed upon the earliest to occur of a separation from service (subject to a six month payment delay for certain specified employees under Section 409A of the Internal Revenue Code), the participant’s death, a change in control or a specified date selected by the participant in accordance with the terms of the NQDC Plan. Benefits are distributed from the NQDC Plan in the form of a lump sum payment or, in certain circumstances if elected by the participant, in the form of annual installments for up to a five-year period.


Nonqualified Deferred Compensation Table
The NQDC Plan benefits for Mr. Cunningham were charged to us in 20172022 pursuant to the Omnibus Agreement. The following table provides information regarding all contributions to, and the year-end balance of, the NQDC Plan account for Mr. Cunningham. Even though Messrs. Damiris andJennings, Harrison, Voliva and Ms. McWatters areBhatia were also participants in the NQDC Plan in 2022, we have not provided any disclosure with respect to their NQDC Plan benefits since those benefits were entirely paid for by HFCHF Sinclair during 2017.2022. Additional information regarding the NQDC Plan, and participation in the NQDC Plan by Messrs. DamirisJennings and Voliva and Ms. McWatters,Bhatia will be provided in HFC’s 2018HF Sinclair’s 2023 Proxy Statement.


NameExecutive Contributions in 2017 (1)
Company
Contributions in 2017 (2)
Aggregate
Earnings in 2017
Aggregate
Withdrawals/
Distributions in 2017

Aggregate Balance
at December 31, 2017 (3)
NameExecutive Contributions in 2022 (1)Company Contributions in 2022 (2)Aggregate
Earnings in 2022		Aggregate
Withdrawals/
Distributions in 2022

Aggregate Balance
at December 31, 2022 (3)
George J. Damiris—
—
—
—
—
Michael C. JenningsMichael C. Jennings— — — — — 
John HarrisonJohn Harrison— — — — — 
Vaishali S. BhatiaVaishali S. Bhatia— — — — — 
Mark T. CunninghamMark T. Cunningham$3,636— ($63,572)$292,231$1,176,580
Richard L. Voliva III—
—
—
—
—
Richard L. Voliva III— — — — — 
Mark T. Cunningham$72,330
$18,579
$41,387
—
$703,639
Denise C. McWatters—
—
—
—
—
_______________



(1)The amounts reported were deferred at the election of the Named Executive Officer and are also included in the amounts reported in the “Salary,” “Bonus” and/or “Non-Equity Incentive Plan Compensation” columns of the Summary Compensation Table for 2017.

(2)These amounts are also included in the “All Other Compensation” column of the Summary Compensation Table for 2017.

(3)The aggregate balance for Mr. Cunningham reflects the cumulative value, as of December 31, 2017, of his and employer-provided contributions to the NQDC Plan for his account, and any earnings on these amounts, since he began participating in the NQDC Plan in 2012. We reported executive and company contributions for Mr. Cunningham in the Summary Compensation Table in the following aggregate amounts:

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Name2017Years Prior to 2017
Mark T. Cunningham$90,909$ 529,243


(1)    The amounts reported were deferred at the election of the Named Executive Officer and are also included in the amounts reported in the “Salary,” “Bonus” and/or “Non-Equity Incentive Plan Compensation” columns of the Summary Compensation Table for 2022.

(2)    These amounts are also included in the “All Other Compensation” column of the Summary Compensation Table for 2022.

(3)    The aggregate balance for Mr. Cunningham reflects the cumulative value, as of December 31, 2022, of his and employer-provided contributions to the NQDC Plan for his account, and any earnings on these amounts, since he began participating in the NQDC Plan in 2012. We reported executive and company contributions for Mr. Cunningham in the Summary Compensation Table in the following aggregate amounts:

Name2022Years Prior to 2022
Mark T. Cunningham$3,636$1,294,045

Potential Payments upon Termination or Change in Control


We havehad a Change in Control Agreement with Mr. Cunningham until his Retirement and we maintain the Long-Term Incentive Plan, each of which provideprovides for potential severance compensation and/or accelerated vesting of equity compensation in the event of a termination of employment following a change in control or under other specified circumstances. These arrangements are summarized below.However, as of December 31, 2022, none of our Named Executive Officers were eligible for benefits from us pursuant to a Change in Control Agreement, our Long-Term Incentive Plan, or the new Severance Pay Plan adopted in 2022.


Change in Control Agreements


HF Sinclair entered into a Change in Control Agreement with each of Messrs. Jennings, Voliva and Harrison and Ms. Bhatia. Mr. Voliva’s HF Sinclair Change in Control Agreement terminated upon his separation on September 15, 2022. Payments and benefits under the HF Sinclair Change in Control Agreements are triggered only upon certain termination events in connection with a change in control of HF Sinclair. A summary of the terms of the HF Sinclair Change in Control Agreements, and a quantification of potential benefits under the HF Sinclair Change in Control Agreement with Mr. Jennings and Ms. Bhatia, will be disclosed in HF Sinclair’s 2023 Proxy Statement.

We entered into a Change in Control Agreement with Mr. Cunningham, effective as of February 14, 2011, and bear all costs and expenses associated with such agreement.his agreement terminated effective upon his retirement on February 18, 2022. We entered into a Change in Control Agreement with Mr. Voliva, effective as of April 28, 2014, whichand such agreement was terminated on October 31, 2016 when he entered into a Change in Control Agreement with HFC.

In 2017, HFC had a Change in Control Agreement with eachHF Sinclair. Therefore, as of Messrs. Damiris and Voliva and Ms. McWatters. Payments and benefits under the HFCFebruary 18, 2022, there are no Change in Control Agreements are triggered only upon certain termination events in connectionthat we currently maintain with a change in control of HFC. A summary of the terms of the HFC Change in Control Agreements, and a quantification of potential benefits under the HFC Change in Control Agreements with Messrs. Damiris and Voliva and Ms. McWatters will be disclosed in HFC’s 2018 Proxy Statement.Named Executive Officer.

Each Change in Control Agreement under our Change in Control Policy terminates on the day prior to the three-year anniversary of its effective date, and thereafter automatically renews for successive one-year terms (on each anniversary date thereafter) unless a cancellation notice is given by us 60 days prior to the automatic extension date. The Change in Control Agreements provide that if, in connection with or within two years after a “Change in Control” of HFC, HLS or HEP (1) the executive’s employment is terminated by HFC, HLS, HEP Logistics or HEP without “Cause,” by the employee for “Good Reason,” or as a condition of the occurrence of the transaction constituting the “Change in Control,” or (2) the executive does not remain employed by HFC, HLS, HEP Logistics or HEP or any of their respective affiliates or the executive is not offered employment with HFC, HLS, HEP, HEP Logistics or any of their affiliates on substantially the same terms in the aggregate as his previous employment within 30 days after the termination, then the executive will receive the following cash severance amounts paid by us:

an amount equal to his accrued and unpaid salary, unreimbursed expenses and accrued vacation pay; and

a lump sum amount equal to a designated multiplier times (i) the executive’s annual base salary as of the date of termination or the date immediately prior to the “Change in Control,” whichever is greater, and (ii) the executive’s annual bonus amount, calculated as the average annual bonus paid to him for the prior three years. The severance multiplier is 1.0 for Mr. Cunningham.

The executive will also receive continued participation by the executive and his or her dependents in medical and dental benefits for the number of years equal to the executive’s designated severance multiplier, which, in the case of Mr. Cunningham, is one year.



For purposes of the Change in Control Agreements, a “Change in Control” occurs if:

a person or group of persons (other than HFC or any of its wholly-owned subsidiaries; HLS, HEP, HEP Logistics or any of their subsidiaries) becomes the beneficial owner of more than 50% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics or more than 50% of the outstanding common stock or membership interests, as applicable or HFC or HLS;
the individuals who as of the date of grant constituted a majority of HFC’s Board of Directors and individuals whose election by HFC’s Board of Directors, or nomination for election by the holders of the voting securities of HFC, was approved by a vote of at least two-thirds of the directors, cease for any reason to constitute a majority of HFC’s Board of Directors;
the consummation of a merger, consolidation or recapitalization of HFC, HLS, HEP or HEP Logistics resulting in the holders of voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, prior to the merger or consolidation owning less than 50% of the combined voting power of the voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, or a recapitalization of HFC, HLS, HEP or HEP Logistics in which a person or group becomes the beneficial owner of securities of HFC, HLS, HEP or HEP Logistics, as applicable, representing more than 50% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics, as applicable;
the holders of voting securities of HFC or HEP approve a plan of complete liquidation or dissolution of HFC or HEP, as applicable; or
the holders of voting securities of HFC or HEP approve the sale or disposition of all or substantially all of the assets of HFC or HEP, as applicable, other than to an entity holding at least 60% of the combined voting power of the voting securities immediately prior to such sale or disposition.

For purposes of the Change in Control Agreements, “Cause” is defined as:

the engagement in any act of willful gross negligence or willful misconduct on a matter that is not inconsequential; or
conviction of a felony.

For purposes of the Change in Control Agreements, “Good Reason” is defined as, without the express written consent of the executive:

a material reduction in the executive’s (or his supervisor’s) authority, duties or responsibilities;
a material reduction in the executive’s base compensation; or
the relocation of the executive to an office or location more than 50 miles from the location at which the executive normally performed the executive’s services, except for travel reasonably required in the performance of the executive’s responsibilities.

All payments and benefits due under the Change in Control Agreements will be conditioned on the execution and non-revocation by the executive of a release of claims for the benefit of HFC, HLS, HEP and HEP Logistics and their related entities and agents. The Change in Control Agreements also contain confidentiality provisions pursuant to which each executive agrees not to disclose or otherwise use the confidential information of HFC, HLS, HEP or HEP Logistics. Violation of the confidentiality provisions entitles HFC, HLS, HEP or HEP Logistics to complete relief, including injunctive relief. Further, in the event of a breach of the confidentiality covenants, the executive could be terminated for Cause (provided the breach constituted willful gross negligence or misconduct on the executive’s part that is not inconsequential). The agreements do not prohibit the waiver of a breach of these covenants.

If amounts payable to an executive under a Change in Control Agreement (together with any other amounts that are payable by HFC, HLS, HEP or HEP Logistics as a result of a change in ownership or control) exceed the amount allowed under Section 280G of the Internal Revenue Code for such executive by 10% or more, we will pay the executive an amount necessary to allow the executive to retain a net amount equal to the total present value of the payments on the date they are to be paid. Conversely, if the payments exceed the 280G limit for the executive by less than 10%, the payments will be reduced to the level at which no excise tax applies.


Long-Term Equity Incentive Awards


TheNone of our Named Executive Officers have an outstanding long-term equity incentive awardsaward that was granted under the Long-Term Incentive PlanPlan.

Mutual Separation Agreement with Mr. Voliva

HLS and Mr. Voliva agreed to our Named Executive Officers vest upon a “Special Involuntary Termination,” which occurs when, within 60 daysmutual separation effective September 15, 2022 (the “Separation Date”). As discussed above, Mr. Voliva was an HF Sinclair Shared Officer prior to his separation. In connection with Mr. Voliva’s separation, HF Sinclair, HollyFrontier Corporation (“HFC”), HLS, HollyFrontier Payroll Services, Inc., and HEP, on behalf of themselves and their respective parents, subsidiaries and affiliates, and Mr. Voliva entered into a Mutual Separation Agreement and Release dated September 15, 2022 (the “Separation Agreement”). The Separation Agreement set forth the terms of his separation compensation approved by the Board and included the following compensation paid to Mr. Voliva: (i) as a result of his provision of services to HEP and HLS during substantially all of the 2022 performance period ending on September 30, 2022, he received a 2022 annual incentive cash bonus of $600,000, which was 150% of his target bonus of $400,000 and was estimated to be at or near the expected actual payout for the 2022 performance period at anythe time after a “Change in Control”:



the executive’s employment is terminated, other than for “Cause,” or

the executive resigns within 90 days following an “Adverse Change.”

Allof his separation, and (ii) pro rata vesting of his outstanding performance units will vest at 150%phantom unit award, resulting in the eventvesting of a Special Involuntary Termination.

In the event of an executive’s death, disability or retirement, restricted units,14,956 phantom units and performance units vest as follows:granted to him in October 2020.


Restricted Units:Upon death or disability, the executive will vestAs a result of Mr. Voliva’s prior position with respect to a pro rata number of units attributable to the period of service completed during the applicable vesting period and will forfeit any unvested units. Upon retirement, the executive will forfeit any unvested units.

Phantom Units: Upon death or disability, the executive will vest with respect to a pro rata number of units attributable to the period of service completed during the applicable vesting period and will forfeit any unvested units. Upon “Retirement,” the executive will fully vest in all phantom units.

Performance Units:Pursuant toHF Sinclair, the terms of the November 2017 performance unit award agreement, upon retirement the award will remain outstandingSeparation Agreement included, and eligibleMr. Voliva received from HF Sinclair, a separation payment equal to vest without proration subject to actual performance. Upon death, disability and retirement, other than with respect to retirement under the termsone year of the November 2017 performance unit award agreement, the executive will remain eligible to vest with respect to a pro rata numbersalary of units attributable to the period of service completed during the applicable performance period (rounded up to include the month of termination) and will forfeit any unvested units. The Compensation Committee will determine the number of remaining performance units earned and the amount$715,000 to be paid toin twelve monthly
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installments, a one-time cash payment of $100,000, a 2022 annual incentive cash bonus from HF Sinclair in the executive as soon as administratively possible after the endamount of the performance period based upon the performance actually attained for the entire performance period (provided that executives will earn$965,250, and receive payment with respect to no less than 50%pro rata vesting of the performance units awarded). The foregoing also applies if the executive separates from employment for any other reason other than a voluntary separation, Special Involuntary Separation or for “Cause.”

For purposes of the long-termhis HF Sinclair equity incentive awards, a “Change in Control” occurs if:

a person or group of persons (other than HFC or any of its wholly-owned subsidiaries or HLS, HEP, HEP Logistics or any of their subsidiaries) becomes the beneficial owner of more than 40% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics;
the individuals who as of the date of grant constituted a majority of HFC’s Board of Directors cease for any reason to constitute a majority of HFC’s Board of Directors;
the consummation of a merger, consolidation or recapitalization of HFC, HLS, HEP or HEP Logistics resulting in the holdersvesting of voting securities23,953 HF Sinclair restricted stock units and 48,971 HF Sinclair performance share units as of HFC,his Separation Date.

The foregoing severance and bonus payments are subject to Mr. Voliva not later revoking the Separation Agreement, which contains non-solicitation, non-compete, non-disparagement and confidentiality covenants from Mr. Voliva that were still in effect as of December 31, 2022.

Retirement & Consulting Arrangements with Mr. Cunningham

On October 27, 2021, Mr. Cunningham notified the Board that he was retiring from all officer positions and as an employee at HLS HEP or HEP Logistics,and its subsidiaries, effective February 18, 2022 (the “Retirement Date”). In preparation for his Retirement, his responsibilities were transferred to four different individuals at HLS, effective January 1, 2022, rather than replacing his role with a single individual. Due to his expertise, history with HLS, involvement in current projects and the need to orderly transition his duties and knowledge to other individuals at HLS, Mr. Cunningham agreed to serve as applicable, priora consultant to HLS and its subsidiaries for a twelve-month period following his Retirement Date. The terms of this consulting arrangement were included in a consulting agreement entered into between HLS and Mr. Cunningham on October 28, 2021, which became effective on February 19, 2022 (the “Consulting Agreement”). The Consulting Agreement expired pursuant to its terms on February 19, 2023, but was still in effect on December 31, 2022. Pursuant to the merger or consolidation owning less than 60%Consulting Agreement, Mr. Cunningham received a payment of $50,000 per calendar month to provide up to 40 hours per month of services to HLS and its subsidiaries. The Consulting Agreement also included an obligation for Mr. Cunningham to keep information about HLS and its subsidiaries obtained during his time as a consultant confidential. During 2022, Mr. Cunningham received consulting fees from HLS pursuant to the combined voting power of the voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, or a recapitalization of HFC, HLS, HEP, or HEP Logistics in which a person or group becomes the beneficial owner of securities of HFC, HLS, HEP or HEP Logistics, as applicable, representing more than 40% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics, as applicable;
the holders of voting securities of HFC, HLS, HEP or HEP Logistics approve a plan of complete liquidation or dissolution of HFC, HLS, HEP or HEP Logistics, as applicable; or
the holders of voting securities of HFC, HLS, HEP or HEP Logistics approve the sale or disposition of all or substantially all of the assets of HFC, HLS, HEP or HEP Logistics, as applicable, other than to an entity holding at least 60% of the combined voting power of the voting securities immediately prior to such sale or disposition.

For purposes of the restricted unit awards, “Adverse Change” is defined as:

a changeConsulting Agreement in the city in which the executive is required to work;aggregate amount of $517,857.
a substantial increase in travel requirements
The outstanding equity awards that Mr. Cunningham held on his Retirement Date received accelerated vesting. A total of employment;
a substantial reduction in the duties2,092 of the type previously performed by the executive; or
a significant reduction in compensation or benefits (other than bonuseshis phantom units and other discretionary items10,889 of compensation) that does not apply generally to executives.
For purposeshis performance units were accelerated, for an aggregate value of the$229,634 as of his Retirement Date.His vested phantom unit awards and the performance units granted in November 2017, “Retirement” is defined as termination of employment other than for Cause on or after the date on which the executive: (i) has achieved ten years of continuous service and (ii) has attained age sixty.



For purposes of the performance unit awards “Adverse Change” is definedsettled six months following his Retirement Date, as without the consentMr. Cunningham was subject to certain executive officer level deferral requirements imposed by Section 409A of the executive:Code.

a change in the executive’s principal office of employment of more than 25 miles from the executive’s work address at the time of grant of the award;
a material increase (without adequate consideration) or material reduction in the duties to be performed by the executive; or
a material reduction in the executive’s base compensation (other than bonuses and other discretionary items of compensation) that does not apply generally to employees.

For purposes of the long-term equity incentive awards, “Cause” is defined as:

an act of dishonesty constituting a felony or serious misdemeanor and resulting (or intended to result in) gain or personal enrichment to the executive at the expense of HLS;
gross or willful and wanton negligence in the performance of the executive’s material and substantial duties; or
conviction of a felony involving moral turpitude.

Quantification of Benefits
The following table summarizes the compensation and other benefits that would have been payable to the Named Executive Officers under the arrangements described above assuming their employment terminated under various scenarios, including in connection with a change in control, on December 31, 2017. For these purposes, our common unit price was assumed to be $32.49, which was the closing price per unit on December 29, 2017 (the last trading day of 2017).
In reviewing the table, please note the following:

For purposes of determining amounts under the “Cash Payments” column, accrued and unpaid salary and unreimbursed expenses were assumed to equal zero.

Accrued vacation for a specific year is not allowed to be carried over to a subsequent year, so we assumed all accrued vacation for the 2017 year was taken prior to December 31, 2017. Because we accrue vacation in any given year for the following year, amounts reported as “Cash Payments” include vacation amounts accrued in 2017 for the 2018 year.

For amounts payable to the Named Executive Officers with respect to performance units upon a termination due to death, disability, retirement, or other separation (other than a voluntary separation, a for “Cause” separation or a Special Involuntary Termination), we assumed the performance units would settle at 100%. The number of units paid at the end of the performance period may vary from the amounts reflected in the following tables, based on our actual achievement compared to the performance targets. Neither Mr. Voliva nor Mr. Cunningham were eligible for retirement vesting at December 31, 2017.

With respect to the treatment of restricted and phantom unit awards upon termination due to death, disability or without Cause, we have reflected accelerated vesting based on the length of employment during the vesting period for each award.

The amount shown for “Value of Welfare Benefits” represents amounts equal to the monthly premium payable pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”), for medical and dental premiums, multiplied by 12 months for Mr. Cunningham.

In calculating whether any tax reimbursements were owed to the Named Executive Officers, we used the following assumptions: (a)  no amounts will be discounted as attributable to reasonable compensation, (b) all cash severance payments are contingent upon a change in control, and (c) the presumption required under applicable regulations that the equity awards granted in 2017 were contingent upon a change in control could be rebutted. Based on these assumptions, none of the Named Executive Officers would receive any tax reimbursement or “gross-up” payments with respect to any amounts reported in the table below.

No amounts potentially payable pursuant to the NQDC Plan are included in the table below since neither the form nor amount of any such benefits would be enhanced nor vesting or other provisions accelerated in connection with any of the triggering events disclosed below. Please refer to the section titled “Nonqualified Deferred Compensation” for additional information regarding these benefits.



Named Executive OfficerCash Payments
Value of
Welfare Benefits
Vesting
of Equity Awards 
Total
George J. Damiris—
—
—
—
Richard L. Voliva III    
Termination in connection with or following a Change in Control—
—
$79,893
$79,893
Termination due to Death, Disability or without Cause—
—
$39,142
$39,142
Mark T. Cunningham
    Termination in connection with or following a Change in Control
$473,927
$17,430
$887,270
$1,378,627
Termination due to Death, Disability or without Cause—
—
$236,756
$236,756
Denise C. McWatters—
—
—
—



Compensation Practices as They Relate To Risk Management


Although a significant portion of the compensation provided to the Named Executive Officers is performance-based, we believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees) because these programs are designed to encourage employees to remain focused on both our short- and long-term operational and financial goals.


While annual cash-based incentive bonus awards play an appropriate role in the executive compensation program, the Compensation Committee believes that payment determined based on an evaluation of our performance on a variety of measures, including comparing our performance over the last year to our past performance, mitigates excessive risk-taking that could produce unsustainable gains in one area of performance at the expense of our overall long-term interests. In addition, we set performance goals that we believe are reasonable in light of our past performance and market conditions.


For Named Executive Officers performing all or a majority of their services for us, an appropriate part of total compensation is fixed, while another portion is variable and linked to performance. A portion of the variable compensation we provide is comprised of long-term incentives. A portion of the long-term incentives we provide is in the form of restricted or phantom units subject to time-based vesting conditions, which retains value even in a depressed market, so executives are less likely to take unreasonable risks. With respect to our performance units, payouts result in some compensation at levels below full target achievement, in lieu of an “all or nothing” approach. Further, our unit ownership guidelines require certain of our executives to hold at least a specified level of units (in addition to unvested and unsettled equity-based awards), which aligns an appropriate portion of their personal wealth to our long-term performance and the interests of our unitholders.


Also, our Clawback Policy requires the return of annual and long-term incentive compensation for:

•the occurrence of a material financial restatement (other than due to a change in accounting policy or applicable law);
•certain acts of dishonesty constituting a felony or serious misdemeanor and resulting or intending to result directly in gain or personal enrichment at the expense of HLS, HEP or any of its subsidiaries;
•gross or willful and wanton negligence in the performance of material and substantial duties of employment with HLS, HEP and its subsidiaries; and
•felony convictions involving moral turpitude.
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Based on the foregoing and our annual review of our compensation programs, we do not believe that our compensation policies and practices are reasonably likely to have a material adverse effect on us or our unitholders.


CEO Pay Ratio


The employees providing services to us are either provided by HLS, which utilizes people employed by HFCHF Sinclair to perform services for us, or seconded to us by subsidiaries of HFC,HF Sinclair, as we do not have any employees for purposes of the pay ratio rules. Rather than providing a pay ratio disclosure that contemplates no employees, we have determined that the disclosure that would be most aligned with the spirit of the pay ratio rules and that would provide our unitholders with more meaningful information would be to provide a ratio using the median employee from the HFCHF Sinclair employee population. As a result, we have used the same median employee that was identified by HFCHF Sinclair following HFC’sHF Sinclair’s examination of the 2017 total cash and equity compensation2022 taxable wages for all individuals who were employed by HFCHF Sinclair in the U.S. and Canada on December 15, 2017.2022.


HFCHF Sinclair identified the median employee by examining the 2017 W-2 (for U.S. employees) and T4 (for Canadian employees)2022 taxable wages for all of its U.S. and Canadian employees, including its CEO, who were employed by HFCHF Sinclair on December 15, 2017. HFC2022. HF Sinclair included all U.S. and Canadian employees, whether employed on a full-time, part-time, temporary or seasonal basis.As of December 15, 2017 HFC2022, HF Sinclair employed 3,4475,005 such persons.As permitted by the SEC rules, HFCHF Sinclair excluded its 231 employees located in EuropeChina, Germany, the Netherlands and Asiathe U.K. since those employees comprise less than 5% of HFC’s totalHF Sinclair’s 5,236 worldwide employees. HFCHF Sinclair did not make any assumptions, adjustments or estimates with respect to the W-2 or T4taxable wages other than deducting stock vesting from the taxable wages, and HFCHF Sinclair did not annualize the compensationwages for any


employees that were not employed by HFCHF Sinclair for all of 2017. HFC2022. HF Sinclair believes the use of W-2 or T4taxable wages as applicable, is the most appropriate compensation measure since it includes the total taxable compensation received by itsallows for a consistent measurement for employees in 2017. different countries.


After identifying the median employee based on total cash and equity compensation, HFCtaxable wages, HF Sinclair calculated annual 20172022 compensation for the median employee using the methodology provided in the SEC rules. HFC’sHF Sinclair’s median employee’s annual 20172022 compensation was as follows:

NameYearSalaryStock AwardsNon-Equity
Incentive Plan
Compensation		All Other
Compensation		Total
Median Employee2022$131,620—$6,866$12,664$151,150
NameYearSalaryBonusStock Awards
Non-Equity
Incentive Plan
Compensation
All Other
Compensation
Total
Median Employee2017$115,400——$4,510$11,702$131,612


Our 20172022 ratio of chief executive officer total compensation to the HFCHF Sinclair median employee’s total compensation is reasonably estimated to be 15:23:1.




Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters


The following table sets forth as of February 14, 201815, 2023 the beneficial ownership of common units of HEP held by:


•each person known to us to be a beneficial owner of 5% or more of the common units;
•directors of HLS, the general partner of our general partner;
•each Named Executive Officer of HLS; and
•all directors and executive officers of HLS as a group.


The percentage of common units noted below is based on 105,268,955126,440,201 common units outstanding as of February 14, 2018.15, 2023. Unless otherwise indicated, the address for each unitholder is c/o Holly Energy Partners, L.P., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507.


Beneficial ownership of the common units of HEP is determined in accordance with SEC rules and regulations and generally includes voting power or investment power with respect to the common units held. Except as indicated and subject to applicable community property laws, to our knowledge the persons named in the tables below have sole voting and investment power with respect to all common units shown as beneficially owned by them. Except to the extent otherwise disclosed below, the directors and named executive officers have no shares pledged as securities nor do they have any other rights to acquire beneficial ownership of shares.


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Name of Beneficial OwnerCommon UnitsPercentage of Outstanding Common Units
HollyFrontier Corporation(1)
59,630,030
56.6%
Tortoise Capital Advisors, L.L.C.(2)
6,717,745
6.4%
Energy Income Partners, LLC(3)
6,425,272
6.1%
Oppenheimer Funds, Inc.(4)
5,551,785
5.3%
Mark T. Cunningham(5)
49,117
*
Michael C. Jennings(6)(7)
20,978
*
Richard L. Voliva III(5)(7)
5,506
*
Denise C. McWatters(7)
4,881
*
Larry R. Baldwin(6)
6,516
*
James H. Lee(6)(7)(8)
5,039
*
George J. Damiris(7)
—
*
R. Kevin Hardage(7)
—
*
All directors and executive officers as group (8 persons)(9)
92,037
*
Name of Beneficial OwnerCommon UnitsPercentage of Outstanding Common Units
HF Sinclair Corporation(1)
59,630,030 47.2%
REH Company(2)
21,000,000 16.6%
ALPS Advisors, Inc.(3)
6,821,862 5.4%
Mark T. Cunningham(4)
84,833 *
Robert I. Jamieson(5)
38,354 *
Larry R. Baldwin(6)
36,150 *
Christine B. LaFollette(6)
30,698 *
Eric L. Mattson(6)
28,698 *
Michael C. Jennings(7)
26,377 *
James H. Lee(6)(7)(8)
26,344 *
Mark A. Petersen(6)
10,463 *
John Harrison(7)
— *
Vaishali S. Bhatia(7)
— *
Richard L. Voliva III (9)
— *
All directors and executive officers as group (9 persons)(10)
197,084 *



* Less than 1%
(1)HollyFrontier Corporation directly holds 5,006 common units over which it has sole voting and dispositive power and 59,625,024 common units over which it has shared voting and dispositive power. HollyFrontier Corporation is the record


(1)Certain direct and indirect wholly owned subsidiaries of HF Sinclair Corporation, including HollyFrontier Corporation, HollyFrontier Holdings LLC, Navajo Pipeline Co., L.P., HollyFrontier Navajo Refining LLC, HEP Logistics Holdings, L.P., HollyFrontier Woods Cross Refining LLC and Holly Logistics Limited LLC, are the record owners of 59,630,030 of these Common Units. HollyFrontier Corporation directly holds 5,006 common units over which it has sole voting and dispositive power and 59,625,024 common units over which it has shared voting and dispositive power. HollyFrontier Corporation is the record holder of 140,000 common units as nominee for Navajo Pipeline Co., L.P. The 59,625,024 common units over which HollyFrontierHF Sinclair Corporation has shared voting and dispositive power are held as follows: HEP Logistics Holdings, L.P. directly holds 37,250,000 common units; Holly Logistics Limited LLC directly holds 21,615,230 common units; HollyFrontier Holdings LLC directly holds 184,800 common units; Navajo Pipeline Co., L.P. directly holds 254,880 common units; and other wholly-owned subsidiaries of HollyFrontierHF Sinclair Corporation directly own 180,114 common units. HollyFrontierHF Sinclair Corporation is the ultimate parent company of each such entity and may therefore be deemed to beneficially own the units held by each such entity. HollyFrontierHF Sinclair Corporation files information with, or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Exchange Act. The address of HollyFrontierHF Sinclair Corporation is 2828N. Harwood, Suite 1300, Dallas, Texas 75201-1507.
(2)According to a Schedule 13D filed on March 24, 2022 by The Sinclair Companies (now known as REH Company) (“REH”) and Carol Orme Holding, REH has shared voting power with respect to 21,000,000 common units and shared dispositive power with respect to 15,710,000 common units, and Mrs. Holding has shared voting power with respect to 21,000,000 common units and share dispositive power with respect to 15,710,000 common units. As a result of her relationship with REH, Mrs. Holding is deemed to beneficially own such common units under applicable securities law and SEC guidance. Mrs. Holding, however, does not intend ever to own such common units directly for investment purposes in the future and expressly disclaims such beneficial ownership to the maximum extent permitted by law. The address for REH and Mrs. Holding is 550 East South Temple, Salt Lake City, Utah 84102.
(3)Based on a Schedule 13G/A filed with the Securities and Exchange Commission on February 13, 2023, ALPS Advisors, Inc. ("AAI") acts as an investment adviser to certain investment companies , including Alerian MLP ETF (the "Funds"). AAI has shared voting power and shared dispositive power over 6,821,862 common units owned by the Funds and may be deemed to be the beneficial owner of such common units. The 6,821,862 common units that AAI may be deemed to beneficially own include 6,821,862 common units that the Funds may be deemed to beneficially own as of December 31, 2022. The address of AAI and Alerian MLP EFT is 1290 Broadway, Suite 1000, Denver, Colorado 80203.
(4)Mr. Cunningham retired as Senior Vice President, Operations and Engineering of HLS effective February 18, 2022.
(5)The number reported does not include unvested phantom units and performance units.
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(6)The number reported includes 6,150 common units to be issued to the non-employee director upon settlement of phantom units, some of which may vest and be settled within 60 days of February 15, 2023 under certain circumstances. Until settled, the non-employee director has no voting or dispositive power over the common units underlying the phantom units.
(7)Messrs. Jennings, Harrison and Lee and Ms. Bhatia each own common stock of HF Sinclair. Each of these individuals own common stock of HF Sinclair as set forth in the following table:

(2)Based on information provided to the Company by Tortoise Capital Advisors, L.L.C, pursuant to an investment advisory agreement or an investment management agreement entered into with certain investment companies, Tortoise Capital Advisors, L.L.C holds sole voting and dispositive power with respect to 6,717,745 common units held by such investment companies. The address of Tortoise Capital Advisors, L.L.C. is 1550 Ash Street, Suite 300, Leawood, Kansas 66211.
(3)Based on the Schedule 13G/A filed with the Securities and Exchange Commission on February 14, 2018 by Energy Income Partners, LLC, James J. Murchie, Eva Pao, Linda A. Longville, Saul Ballesteros and John K. Tysseland. James J. Murchie, Eva Pao, and John K. Tysseland are the Portfolio Managers with respect to the portfolios managed by Energy Income Partners, LLC. Linda A. Longville and Saul Ballesteros are control persons of Energy Income Partners, LLC. Each of the foregoing report shared voting and dispositive power over 6,425,272 common units. The address of each of the foregoing is 10 Wright Street, Westport, Connecticut 06880.
(4)
Based on a Schedule 13G/A filed with the Securities and Exchange Commission on February 7, 2018, Oppenheimer Funds, Inc. has shared voting power and shared dispositive power with respect to 5,551,785 units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281.
(5)The number reported includes restricted units for which the executive has sole voting power but no dispositive power, as follows: Mr. Voliva (447 units) and Mr. Cunningham (4,336 units). For Mr. Cunningham, also includes 3,861 common units to be issued upon settlement of phantom units, which may vest and be settled within 60 days of February 14, 2018 under certain circumstances. Until settled, Mr. Cunningham has no voting or dispositive power over the phantom units. The number does not include performance units held by the executive.
(6)For each of Mr. Jennings and Mr. Baldwin, includes 2,557 restricted units for which he has sole voting power but no dispositive power. For Mr. Lee, includes 2,754 restricted units for which he has sole voting power but no dispositive power.
(7)Messrs. Jennings, Damiris, Voliva, Lee and Hardage and Ms. McWatters each own common stock of HFC. Each of these individuals own common stock of HFC as set forth in the following table:

Name of Beneficial OwnerNumber of Shares
George J. Damiris
Michael C. Jennings (a)
280,747101,164 
Denise C. McWatters (a)63,258
Richard L. Voliva III (a)(b)59,683
James H. Lee (c)(b)
52,240
Michael C. Jennings (c)45,917
R. Kevin Hardage (c)30,819
Total532,664

57,101 
Vaishali S. Bhatia(a)
The number reported includes shares of HFC restricted stock for which the individual has sole voting power but no dispositive power, as follows: Mr. Damiris (105,149 shares), Ms. McWatters (15,528 shares) and Mr. Voliva (16,444 shares). Also includes shares of HFC common stock to be issued to the individual upon settlement of restricted stock units, which may vest and be settled within 60 days of February 14, 2018 under certain circumstances, as follows: Mr. Damiris (77,961 shares), Mr. Voliva (19,491 shares) and Ms. McWatters (11,813 shares). Until settled, the individual has no voting or dispositive power over the restricted stock units. The number does not include unvested performance share units.
18,465 
(b)
John Harrison(a)
The number reported includes 3,778 shares of HFC restricted stock and 2,271 restricted stock units held by Mr. Voliva’s wife for which Mr. Voliva disclaims beneficial ownership except to the extent of his pecuniary interest therein.
17,915 
(c)TotalThe number reported includes 3,190 shares of HFC common stock to be issued to the individual upon settlement of restricted stock units, which may vest and be settled within 60 days of February 14, 2018 under certain circumstances. Until settled, the individual has no voting or dispositive power over the common stock underlying the restricted stock units.194,645 




(a)The number does not include unvested restricted stock units and performance share units.
(b)The number reported includes 2,643 shares of HF Sinclair common stock to be issued to Mr. Lee, as a non-employee director, upon settlement of restricted stock units, which may vest and be settled within 60 days of February 15, 2023 under certain circumstances. Until settled, Mr. Lee has no voting or dispositive power over the common stock underlying the restricted stock units.

As of February 14, 2018,15, 2023, there were 256,015,579196,186,461 shares of HFCHF Sinclair common stock outstanding. Each of Messrs. Jennings, Damiris, Voliva,Harrison and Lee and Hardage and Ms. McWattersBhatia owns less than 1% of the outstanding common stock of HFC.HF Sinclair.
(8)Includes 285 common units held by Mr. Lee’s wife. Mr. Lee’s wife has the right to receive distributions from, and the proceeds from the sale of, these common units. Mr. Lee disclaims beneficial ownership of the common units held by his wife except to the extent of his pecuniary interest therein.
(9)The number reported includes 4,783 restricted units held by executive officers for which they have sole voting power but no dispositive power, 3,861 common units to be issued to Mr. Cunningham upon settlement of phantom units, which may vest and be settled within 60 days of February 14, 2018 under certain circumstances and 7,868 restricted units held by non-employee directors for which they have sole voting power but no dispositive power. The number reported also includes 285 common units as to which Mr. Lee disclaims beneficial ownership, except to the extent of his pecuniary interest therein.

(8) The number reported includes 285 common units held by Mr. Lee’s wife. Mr. Lee’s wife has the right to receive distributions from, and the proceeds from the sale of, these common units. Mr. Lee disclaims beneficial ownership of the common units held by his wife except to the extent of his pecuniary interest therein.
(9) HLS and Richard L. Voliva III, former President of HLS, agreed to a mutual separation effective September 15, 2022.
(10) The number reported includes 30,750 common units to be issued to the non-employee directors upon settlement of phantom units. Until settled, the non-employee directors have no voting or dispositive power over the common stock underlying the phantom units. The number reported also includes 285 common units as to which Mr. Lee disclaims beneficial ownership, except to the extent of his pecuniary interest therein.

Equity Compensation Plan Table
The following table summarizes information about our equity compensation plans as of December 31, 2017:2022:
Plan Category (1)
Number of securities to be issued upon exercise of outstanding options, warrants and rightsWeighted average exercise price of outstanding options, warrants and rightsNumber of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders (2)
201,513 (3)
—773,014
Equity compensation plans not approved by security holders———
Total201,513—773,014
Plan Category (1)Number of securities to be issued upon exercise of outstanding options, warrants and rightsWeighted average exercise price of outstanding options, warrants and rightsNumber of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders (2)48,941 (3)—1,341,216
Equity compensation plans not approved by security holders———
Total48,941—1,341,216


(1)All stock-based compensation plans are described in Note 9 to our consolidated financial statements for the fiscal year ended December 31, 2022.
(1)All stock-based compensation plans are described in Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2017.

(2)(2)On April 25, 2012, at a Special Meeting of the Unitholders of the Partnership, the unitholders approved the Amended and Restated Long-Term Incentive Plan, which, among other things, provided for an increase in the maximum number of common units reserved for delivery with respect to awards under the Long-Term Incentive Plan to 2,500,000 common units (as adjusted to reflect the two-for-one common unit split that occurred on January 16, 2013). All securities reported as available for future issuances are available from the additional common units approved by unitholders under the Amended and Restated Long-Term Incentive Plan. At the time the Long-Term Incentive Plan was originally adopted in 2004, it was not required to be approved by the Partnership’s unitholders.

(3)Represents units subject to performance units granted to key individuals under the Long-Term Incentive Plan assuming the maximum payout level. If the performance units are paid at the target payout level, 32,628 units would be issued upon the vesting of such performance units. Performance units granted in October 2014 with a performance period that ended on December 31, 2017 were not settled until certification by the subcommittee of the Compensation Committee in February 2018 that a performance percentage of 150% was attained for performance units granted to Mr. Cunningham; however, such awards are not included in this column as outstanding since they are treated for purposes of the preceding executive compensation tables as vesting during 2017 in accordance with SEC rules.

For more information about our Amended and Restated Long-Term Incentive Plan, referwhich, among other things, provided for an increase in the maximum number of common units reserved for delivery with respect to Item 11, “Executive Compensation - Overview of 2017 Executive Compensation Components and Decisions -awards under the Long-Term Incentive Equity Compensation.”Plan to 2,500,000 common units (as adjusted to reflect the two-for-one common unit split that occurred on January 16, 2013). All securities reported as

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available for future issuances are available from the additional common units approved by unitholders under the Long-Term Incentive Plan. At the time the Long-Term Incentive Plan was originally adopted in 2004, it was not required to be approved by HEP’s unitholders.
(3)Includes 85,704 units subject to performance units granted to key individuals under the Long-Term Incentive Plan assuming the maximum payout level. If the performance units are paid at the target payout level, 42,852 units would be issued upon the vesting of such performance units.


Item 13.Certain Relationships and Related Transactions, and Director Independence

Item 13.Certain Relationships and Related Transactions, and Director Independence

Our general partner and its affiliates own 59,630,030 of our common units representing a 57%47% limited partner interest in us. In addition, the general partner owns the non-economic general partner interest in us. Further, REH Company, our next largest unitholder, owns 21,000,000 of our common units representing a 16.6% limited partner interest in us. Transactions with our general partner and REH Company are discussed later in this section.




DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES




The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and liquidation of HEP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.


Operational stage
Distributions of available cash to our general partner and its affiliatesWe generally makecurrently distribute all of our available cash distributions 98% to unitholders of record on the unitholders, including our general partner and its affiliates asapplicable record date within 45 days after the holdersend of an aggregate of 22,380,030 of the common units and 2% to the general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner is entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.each quarter, pro rata.
Payments to our general partner and its affiliatesWe pay HFCHF Sinclair or its affiliates an administrative fee, $2.5currently $5.0 million per year, for the provision of various general and administrative services for our benefit. The administrative fee may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from HFCHF Sinclair or its affiliates. In connection with the HEP Transaction, we paid HF Sinclair a temporary monthly fee of $62,500 through November 30, 2022, relating to transition services provided to HEP by HF Sinclair. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of HFCHF Sinclair who provide services to us on behalf of HLS. Finally, HLS is required to reimburse HFCHF Sinclair for our benefit pursuant to the secondment arrangement for the wages, benefits, and other costs of HFCHF Sinclair employees seconded to HLS to perform services at certain of our pipelines and tankage assets. Please read “Omnibus Agreement” and “Secondment Arrangement” below. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partnerIf our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.


Liquidation stage
LiquidationUpon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.


OMNIBUS AGREEMENT


Our Omnibus Agreement with HFCHF Sinclair and our general partner that addresses the following matters:


•our obligation to pay HFCHF Sinclair an annual administrative fee, in the amount of $2.5$5.0 million for 2017,2022, for the provision by HFCHF Sinclair of certain general and administrative services;
HFC’s
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•HF Sinclair's and its affiliates’ agreement not to compete with us under certain circumstances and our right to notice of, and right of first offer to purchase, certain logistics assets constructed by HFCHF Sinclair and acquired as part of an acquisition by HFCHF Sinclair of refining assets;
•an indemnity by HFCHF Sinclair for certain potential environmental liabilities;
•our obligation to indemnify HFCHF Sinclair for environmental liabilities related to our assets existing on the date of our initial public offering to the extent HFCHF Sinclair is not required to indemnify us; and
HFC’s•HF Sinclair’s right of first refusal to purchase our assets that serve HFC’s refineries.HF Sinclair’s refineries; and

•our obligation to pay HF Sinclair a temporary administrative services fee, in the amount of $62,500 per month, related to certain transition services in connection with the HEP Transaction.

Payment of general and administrative services fee and temporary monthly fee
Under the Omnibus Agreement, we pay HFCHF Sinclair an annual administrative fee, in the amount of $2.5$5.0 million for 2017,2022, for the provision of various general and administrative services for our benefit. This fee is subject to annual adjustment for changes in the Producer Price Index Commodities - Finished Goods, et al. Our general partner may agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses.


The administrative fee includes expenses incurred by HFCHF Sinclair and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. TheIn connection with the HEP Transaction, we paid HF Sinclair a temporary monthly fee does not includeof $62,500 through November 30, 2022, relating to transition services provided to HEP by HF Sinclair. Neither the annual administrative fee nor the temporary monthly fee includes salaries of pipeline and terminal personnel or other employees of HFCHF Sinclair who perform services for us on behalf of HLS or the cost of their employee benefits, such as 401(k), pension, and health insurance benefits, which are


separately charged to us by HFC.HF Sinclair. We also reimburse HFCHF Sinclair and its affiliates for direct general and administrative expenses they incur on our behalf.


Noncompetition
HFCHF Sinclair and its affiliates have agreed, for so long as HFCHF Sinclair controls our general partner, not to engage in, whether by acquisition or otherwise, the business of operating crude oil pipelines or terminals, refined product pipelines or terminals, intermediate pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. This restriction will not apply to:


•any business operated by HFCHF Sinclair or any of its affiliates at the time of the closing of our initial public offering;
•any business conducted by HFCHF Sinclair with the approval of our general partner;
•any business or asset that HFCHF Sinclair or any of its affiliates acquires or constructs that has a fair market value or construction cost of less than $5 million; and
•any business or asset that HFCHF Sinclair or any of its affiliates acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.


The limitations on the ability of HFCHF Sinclair and its affiliates to compete with us will terminate if HFCHF Sinclair ceases to control our general partner.


Indemnification
Under the Omnibus Agreement, certain transportation agreements and purchase agreements with HFC, HFCHF Sinclair, HF Sinclair has agreed to indemnify us, subject to certain limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFCHF Sinclair and occurring or existing prior to the date of such transfers. The Omnibus Agreement provides environmental indemnification with respect to certain transferred assets of up to $2.5 million through 2019, $7.5 million through 2023 and $15 million through 2026. HFC'sHF Sinclair's indemnification obligations under the Omnibus Agreement do not apply to assets we acquire from third parties, assets we construct or assets we relocate after they are transferred to us from HFC.HF Sinclair. For the Tulsa loading racks acquired from HFCHF Sinclair in August 2009 and the Tulsa logistics and storage assets acquired from Sinclair in December 2009, HFCHF Sinclair agreed to indemnify us for environmental liabilities arising from our pre-ownership operations of these assets. Additionally, HFCHF Sinclair agreed to indemnify us for any liabilities arising from its operation of our loading racks located at HFC's Tulsa refinery west facility.


We have indemnified HFCHF Sinclair and its affiliates against environmental liabilities related to events that occur on our assets after the date we acquired such asset.

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Right of first refusal to purchase our assets
The Omnibus Agreement also contains the terms under which HFCHF Sinclair has a right of first refusal to purchase our assets that serve its refineries. Before we enter into any contract to sell pipeline and terminal assets serving HFC’sHF Sinclair’s refineries, we must give written notice of the terms of such proposed sale to HFC.HF Sinclair. The notice must set forth the name of the third-party purchaser, the assets to be sold, the purchase price, all details of the payment terms and all other terms and conditions of the offer. To the extent the third-party offer consists of consideration other than cash (or in addition to cash), the purchase price shall be deemed equal to the amount of any such cash plus the fair market value of such non-cash consideration, determined as set forth in the Omnibus Agreement. HFCHF Sinclair will then have the sole and exclusive option for a period of thirty days following receipt of the notice, to purchase the subject assets on the terms specified in the notice.


SECONDMENT ARRANGEMENT


Under HLS’s secondment arrangement with HFC,HF Sinclair, certain employees of HFCHF Sinclair are seconded to HLS, our general partner’s general partner, to provide operational and maintenance services with respect to certain of our pipelines, terminals and refinery processing units, including routine operational and maintenance activities. During their period of secondment, the seconded employees are under the management and supervision of HLS. HLS is required to reimburse HFCHF Sinclair for our benefit for the cost of the seconded employees, including their wages and benefits, based on the percentage of the employee’s time spent working for HLS. The secondment arrangement continues until HLS’s mutual agreement with HFCHF Sinclair to terminate.




PIPELINE AND TERMINAL, TANKAGE AND THROUGHPUT AGREEMENTS


We serve HFC’sHF Sinclair’s refineries and renewable diesel facilities under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring in 20192023 to 2036. Under these agreements, HFCHF Sinclair agrees to transport, store and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminal, tankage and 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 tariff rate adjustments on July 1st each year, based on the PPI or the FERC index. As of December 31, 2017,2022, these agreements with HFCHF Sinclair require minimum annualized payments to us of $324$452.6 million.In connection with the Sinclair Transactions, we amended our master throughput agreement with HF Sinclair to add Sinclair Oil as a shipper and encompass the acquired Sinclair Assets (as defined therein), and we amended our master lease and access agreement with HF Sinclair to, among other things, include certain Sinclair assets in the list of assets comprising the Applicable Assets (as defined therein).


HFC’sHF Sinclair’s obligations under these agreements will not terminate if HFCHF Sinclair and its affiliates no longer own the general partner. These agreements may be assigned by HFCHF Sinclair only with the consent of our conflicts committee.


SUMMARY OF TRANSACTIONS WITH HFCHF SINCLAIR


On•We reached an agreement with HFC to terminate the existing minimum volume commitments for HEP's Cheyenne assets and enter into new agreements, which were finalized and executed on February 22, 2016,8, 2021, 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 obtained(and now HF Sinclair) will pay a 50% membership interest in Osage inbase tariff to HEP for available crude oil storage and HFC (and now HF Sinclair) and HEP will split any profits generated on crude oil contango opportunities and (3) HFC paid a non-monetary exchange$10 million one-time cash payment to HEP for a 20-year terminalling services agreement, whereby a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico requiring terminalling in or through El Paso, Texas. Osage is the ownertermination of the Osage Pipeline, the primary pipeline supplying HFC’s El Dorado refinery with crude oil. Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Since we are a consolidated Variable Interest Entity ("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 treated as a contribution from HFC.existing minimum volume commitment.

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

Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating, a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross refinery, for cash consideration of $278 million.

See “Acquisitions” under Item 1, “Business” of this Annual Report on Form 10-K for additional information on the acquisitions of the crude tanks at HFC's Tulsa refinery and Woods Cross Operating from HFC.

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

•Revenues received from HFCHF Sinclair were $377.1$438.3 million, $333.1$390.8 million and $292.2$399.8 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.

HFC•HF Sinclair charged us general and administrative services under the Omnibus Agreement of $2.5$4.5 million for the year ended December 31, 2017, $2.5 million for the year ended December 31, 2016,2022 and $2.4 million for the year ended December 31, 2015.

We reimbursed HFC for costs of employees supporting our operations of $46.6 million, $40.9 million and $34.5 million for the years ended December 31, 2017, 2016 and 2015, respectively.

HFC reimbursed us $7.2 million, $14.0 million and $13.5 million for the years ended December 31, 2017, 2016 and 2015, respectively, for expense and capital projects.

We distributed $130.7 million, $105.2 million and $90.4 million for the years ended December 31, 2017, 2016 and 2015, respectively, to HFC as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions.



We received operating lease payments from HFC for use of our Artesia and Tulsa railyards for $0.5$2.6 million for each of the years ended December 31, 2017, 20162021 and 2015.2020.

•We reimbursed HF Sinclair for costs of employees supporting our operations of $78.2 million, $61.2 million and $55.8 million for the years ended December 31, 2022, 2021 and 2020, respectively.
•HF Sinclair reimbursed us $14.7 million, $7.9 million and $10.0 million for the years ended December 31, 2022, 2021 and 2020, respectively, for expense and capital projects.
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•We distributed $83.5 million in each of the years ended December 31, 2022 and 2021 and $95.2 million in the year ended December 31, 2020 to HF Sinclair as regular distributions on its common units.
•Accounts receivable from HF Sinclair were $63.5 million and $56.2 million at December 31, 2022 and 2021, respectively.
•Accounts payable to HF Sinclair were $15.8 million and $11.7 million at December 31, 2022 and 2021, respectively.
•Revenues for the years ended December 31, 2022, 2021 and 2020 include $0.4 million, $0.4 million and $0.5 million, respectively, of shortfall payments billed to HF Sinclair in 2021, 2020 and 2019, respectively. Deferred revenue in the consolidated balance sheets at December 31, 2021, includes $4.1 million, relating to certain shortfall billings to HF Sinclair.
•We received direct financing lease payments from HF Sinclair for use of our Artesia and Tulsa railyards of $2.2 million for the year ended December 31, 2022 and $2.1 million for each of the years ended December 31, 2021 and 2020.
•We recorded a gain on sales-type leases of $24.7 million during the year ended December 31, 2021, and we received sales-type lease payments of $91.6 million, $28.9 million and $9.5 million from HF Sinclair that were not included in revenues for the years ended December 31, 2022, 2021 and 2020, respectively.



RELATED PARTY TRANSACTIONS WITH REH COMPANY

Unitholders Agreement
On August 2, 2021, in connection with the Contribution Agreement, HEP, HLS, and Navajo Pipeline Co., L.P., the sole member of HLS (the “Sole Member”) entered into a unitholders agreement (the “Unitholders Agreement”) by and among HEP, HLS, the Sole Member, REH Company (formerly known as The Sinclair Companies) and the stockholders of REH Company (together with REH Company and each of their permitted transferees, the “REH Parties”), which became effective on March 14, 2022, (the "Closing Date"). Pursuant to the Unitholders Agreement, we granted certain director nomination and registration rights to the REH Parties and the REH Parties agreed to certain lock-up restrictions, each as summarized below:

•Director Designee: The REH Parties have the right to nominate, and have nominated, one person to the Board until such time that (x) the REH Parties beneficially own less than 10.5 million common units or (y) the common units beneficially owned by the REH Parties constitute less than 5% of all outstanding common units. REH Company nominated Mark A. Petersen for service as the REH Company designee on the Board, effective as of March 15, 2022.

•Lock-up Restrictions: The Unitholders Agreement subjects 15.75 million of the common units issued to the REH Parties (the “Restricted Units”) to a “lock-up” period commencing on the Closing Date, during which the REH Parties will be prohibited from selling the Restricted Units, except for certain permitted transfers. One-third of such Restricted Units were released from such restrictions on the date that was six months after the closing, one-third of the Restricted Units will be released from such restrictions on the first anniversary of the Closing Date, and the remainder will be released from such restrictions on the date that is 15 months from the Closing Date.

•Registration Rights: The Unitholders Agreement contains customary registration rights, requiring us to file a shelf registration statement to permit the public resale of all the registrable securities held by the REH Parties. We filed such shelf registration statement within five business days following the Closing Date. We also agreed to support underwritten offerings of common units held by the REH Parties within the prescribed time periods outlined in the Unitholders Agreement.

Consulting Agreement
On March 14, 2022, in connection with the closing of the Sinclair Transactions, HLS non-employee director, Mark A. Petersen entered into a consulting agreement with HF Sinclair, pursuant to which he provided certain consulting services to HF Sinclair in 2022 for aggregate compensation in the amount of $120,000. The consulting agreement terminated in October 2022 pursuant to its terms and was approved by the Audit Committee as a related party transaction under Item 404(a) of Regulation S-K. See Item 10 for a discussion of “Director Independence.”

OTHER RELATED PARTY TRANSACTIONS
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Julia Heidenreich, former Vice President, Commercial Analysis and PricingRenewables at HFC,HF Sinclair, is the wife of Richard L. Voliva, HFC's and HLS'sIII, former Executive Vice President and Chief Financial Officer. Prior to being appointed as ViceOfficer of HF Sinclair and former President Commercial Analysis and Pricing at HFC in March 2017, Ms. Heidenreich served as Vice President, Investor Relations for HLS and HFC.of HLS. Ms. Heidenreich received cash and equity compensation totaling $461,075$823,193 in 2017. 2022. All the cash and equity compensation was paid to Ms. Heidenreich by HFCHF Sinclair without any input from HLS. Ms. Heidenreich doesdid not report to Mr. Voliva.Voliva at the time of her employment with HF Sinclair.


REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS


The Board of Directors of our general partner adopted a written related party transactions policy to document procedures for the notification, review, approval, ratification and disclosure of related party transactions. Under the policy, a “related person” includes any director, director nominee, executive officer, or holder (together with any of its controlling or controlled affiliates) of more than 5% percent of our voting units or an immediate family member of any of the foregoing persons or an entity that is owned or controlled by any of the foregoing persons, any of the foregoing persons have a substantial ownership interest or control, or an entity in which any of the foregoing persons is an executive officer or general partner, or holds a similar position. The policy applies to any transaction, arrangement, or relationship or series of similar transactions, arrangements or relationships (including indebtedness or guarantee of indebtedness) in which (i) the aggregate amount involved will or may be expected to exceed $120,000 in any fiscal year, (ii) we, HLS or our subsidiaries are a participant, and (iii) a related person has a direct or indirect material interest.

Certain transactions, including compensation for services provided to a related person, such as an executive officer or director, are pre-approved under the policy. Any transactions between us, our general partner, any of our subsidiaries, on the one hand, and HF Sinclair or any of its subsidiaries, on the other hand, shall be submitted to the Conflicts Committee of our general partner for review and approval in accordance with the process established, and under the authority delegated by the Board of Directors of our general partner to the Conflicts Committee of our general partner for the review, evaluation and approval of intercompany transactions and shall not constitute a related party transaction under the policy.

The policy provides that the Audit Committee of our general partner will be responsible for reviewing and approving related party transactions that may arise within our partnership. The Audit Committee will review the material facts of all related party transactions that require the committee’s approval and either approve or disapprove of the entry into the related party transaction. The policy prohibits any director from participating in any discussion or approval of a related party transaction for which such director is a related person, except that such director is required to provide all material information concerning the interested transaction to the committee. Related party transactions with related persons is governed byrequired to be disclosed in our SEC reports are reported through our disclosure controls and procedures.

The Code of Business Conduct and Ethics which provides guidelines for disclosure, review and approvalgoverns conflicts of anyinterests involving employees who are not covered by the related party transaction that creates a conflict of interest between us and our employees, officers or directors and members of their immediate family.policy described above. Conflict of interest transactions may be authorized if they are found to be in the best interest of the Partnership based on all relevant facts. Pursuant to the Code of Business Conduct and Ethics, conflicts of interest are to be disclosed to and reviewed by a supervisor who does not have a conflict of interest, the Human Resources Department or the Legal and Compliance Department, and approval must be obtained prior to proceeding with the supervisor must report in writing on the action taken to the General Counsel. Conflicts of interest involving directors or senior executive officerspotentially conflicted situation.

There are reviewed by the full Board of Directors or by a committee of the Board of Directors on which the related person does not serve. Related partyno other transactions required to be disclosed in our SEC reports are reported through our disclosure controls and procedures.

There are no transactions disclosed in this Item 13 entered into since January 1, 2017,2022, that were not required to be reviewed, ratified or approved pursuant to our Related Party Transaction Policy or Code of Business Conduct and Ethics or with respect to which our policies and procedures with respect to conflicts of interest were not followed.


See Item 10 for a discussion of “Director Independence.”




Item 14.Principal Accounting Fees and Services

Item 14.Principal Accounting Fees and Services

The audit committee of the board of directors of HLS selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the HEP for the 20172022 calendar year.
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Fees paid to Ernst & Young LLP for 20172022 and 20162021 are as follows:


 2017 201620222021
    
Audit Fees (1)
 $1,154,500
 $937,000
Audit Fees (1)
$1,565,000 $998,000 
Tax Fees 224,000
 202,000
Tax Fees195,000 157,000 
Total $1,378,500
 $1,139,000
Total$1,760,000 $1,155,000 
 
(1)Represents fees for professional services provided in connection with the audit of our annual financial statements and internal controls over financial reporting, review of our quarterly financial statements, and procedures performed as part of our securities filings.
(1)Represents fees for professional services provided in connection with the audit of our annual financial statements and internal controls over financial reporting, review of our quarterly financial statements, and procedures performed as part of our securities filings.
The audit committee of our general partner’s board of directors operates under a written audit committee charter adopted by the board. A copy of the charter is available on our website at www.hollyenergy.com. The charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fee categories above were approved by the audit committee in advance.





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Part IV


Item 15.Exhibits and Financial Statement Schedules

(a)Documents filed as part of this report
(i)Index to Consolidated Financial Statements
Item 15.Exhibits and Financial Statement Schedules

(a)Documents filed as part of this report
(1)Index to Consolidated Financial Statements
Page in
Form 10-K
Page in
Form 10-K
Report of Independent Registered Public Accounting Firm
6574
6676
6777
68
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 20162022, 2021 and 20152020
6978
7079
7180
 
(2)Index to Consolidated Financial Statement Schedules
(2)Index to Consolidated Financial Statement Schedules
All schedules are omitted since the required information is not present in or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.
 
(3)Exhibits
(3)Exhibits
See Index to Exhibits on pages 147158 to 151.162.






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Exhibit Index
Exhibit
Number		Description
Exhibit
Number
2.1†		Description
2.1
Purchase and Sale Agreement, dated February 25, 2008, between Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C., Woods Cross Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 2.1 of Registrant'sRegistrant’s Current Report on Form 8-K dated February 27, 2008, File No. 1-32225).
2.22.2†
Asset Sale and Purchase Agreement, dated October 19, 2009, between Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant'sRegistrant’s Current Report on Form 8-K dated October 21, 2009, File No. 1-32225).
2.3†
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 Registrant’sRegistrant's Current Report on Form 8-K dated August 10, 2017,3, 2021, File No. 1-32225)1-32225).
2.4*†2.4†
First Amendment to Membership PurchaseContribution Agreement, dated as of October 31, 2017,March 14, 2022, by and between Plains Pipeline,among Holly Energy Partners, L.P., The Sinclair Companies, and HEP Casper SLC LLC.

2.5†
Membership Interest Purchase Agreement between Rocky Mountain Pipeline System LLC and HEP SLC, LLC, dated as of August 7, 2017Sinclair Transportation Company (incorporated by reference to Exhibit 2.2 of Registrant’s Current Report on Form 8-K dated August 10, 2017, File No. 1-32225).

2.6
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 (incorporated by reference to Exhibit 2.32.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017,March 31, 2022, File No. 1-32225).

2.7*†3.1
Second Amendment to Membership Purchase Agreement, dated as of October 31, 2017, by and between Rocky Mountain Pipeline System LLC and HEP SLC, LLC.

2.8
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 Registrant’s Current Report on Form 8-K dated October 19, 2017, File No. 1-32225).

3.1
Second Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 toof Registrant’s Current Form on Form 8-K dated November 1, 2017, File No. 1-32225).
3.2
First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners - Operating Company, L.P. (incorporated by reference to Exhibit 3.2 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-32225).
3.3
First Amended and Restated Agreement of Limited Partnership of HEP Logistics Holdings, L.P. (incorporated by reference to Exhibit 3.4 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-32225).
3.4
First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 3.5 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-32225).
3.5
Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C., dated April 27, 2011 (incorporated by reference to Exhibit 3.1 of Registrant'sRegistrant’s Current Report on Form 8-K dated May 3, 2011, File No. 1-32225).
3.6
First Amended and Restated Limited Liability Company Agreement of HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 3.6 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-32225).
4.1
Indenture dated July 19, 2016, among Holly Energy Partners, L.P., Holly Energy Finance Corp., and each of the Guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K dated July 19, 2016, File No. 1-32225).
4.2
First Supplemental Indenture dated November 2, 2016, among Woods Cross Operating LLC, Holly Energy Partners, L.P., and HollyEnergy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016, File No. 1-32225).
4.3
Second Supplemental Indenture, dated July 26, 2017, by and among Holly Energy Holdings LLC, HEP Cheyenne Shortline LLC, the Registrant, Holly Energy Finance Corp., the other guarantors therein and U.S. Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017, File No. 1-32225).



4.4
Registration Rights Agreement, dated February 6, 2018, by and among Holly Energy Partners, L.P. and the various Purchases party thereto (incorporated by reference to Exhibit 4.1 to Registrant'sof Registrant’s Current Report on Form 8-K dated February 7, 2018, File No 1-32225).
4.2
Indenture, dated February 4, 2020, by and among Holly Energy Partners, L.P., Holly Energy Finance Corp., each of the Guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K filed February 4, 2020, File No. 1-32225).
4.3
First Supplemental Indenture, dated as of March 14, 2022, among Sinclair Transportation Company LLC, Sinclair Logistics LLC, Sinclair Pipeline Company LLC, Holly Energy Partners, L.P. and Holly Energy Finance Corp. and the other Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee, related to Holly Energy Partners, L.P.’s 5.000% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022, File No. 001-32225).
4.4
Second Supplemental Indenture, dated as of May 22, 2022, among UNEV Pipeline, LLC, Holly Energy Partners, L.P. and Holly Energy Finance Corp. and the other Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee, related to Holly Energy Partners, L.P.’s 5.000% Senior Notes due 2028 (incorporated by reference to Exhibit 4.7 of Registrant’s Registration Statement on Form S-3 filed on May 23, 2022, File No. 333-265154.).
4.5
Indenture, dated April 8, 2022, by and among Holly Energy Partners, L.P., Holly Energy Finance Corp., each of the Guarantors party thereto and U.S. Bank Trust Company, National Association (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K dated April 8, 2022, File No. 1-32225.).
4.6
First Supplemental Indenture, dated May 22, 2022, among UNEV Pipeline, LLC, Holly Energy Partners, L.P. and Holly Energy Finance Corp. and the other Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee, related to Holly Energy Partners, L.P.’s 6.375% Senior Notes due 2027 (incorporated by reference to Exhibit 4.9 of Registrant’s Registration Statement on Form S-3 filed on May 23, 2022, File No. 333-265154.).
4.7
Description of Capital Stock pursuant to Item 601(b)(4) of Reg S-K (incorporated by reference to Exhibit 4.6 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2019, File No. 1-32225).


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10.1
Third Amended and Restated Credit Agreement, dated July 26, 2017, among Holly Energy Partners, L.P. as borrower, Wells Fargo Bank National Association, as administrative agent, an issuing bank and a lender, and certain other lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K dated July 31, 2017, File No. 1-32225.)

10.210.2†
PipelinesAmendment No. 1 to Third Amended and TerminalsRestated Credit Agreement dated February 28, 2005, betweenApril 30, 2021, among Holly Energy
Partners, L.P., as borrower, certain of its affiliates, as guarantors, Wells Fargo Bank, National Association, as
administrative agent, an issuing bank and ALON USA, LPa lender, and certain other lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant'sRegistrant’s Current Report on Form 8-K dated February 28, 2005,May 3, 2021, File No. 1-32225).
10.310.3†
First Amendment No. 2 to PipelinesThird Amended and TerminalsRestated Credit Agreement betweendated August 15, 2022, among Holly Energy Partners, L.P., as borrower, certain of its affiliates, as guarantors, Wells Fargo Bank, National Association, as administrative agent, an issuing bank and ALON USA, LP, dated September 1, 2008a lender, and certain other lenders party thereto (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-32225).
10.4
Second Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated March 1, 2011 (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-32225).
10.5
Third Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 6, 2011 (incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-32225).
10.6
Fourth Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated October 6, 2014 (incorporated by reference to Exhibit 10.310.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2014,2022, File No. 1-32225)001-32225).
10.710.4
First Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated January 25, 2005 (incorporated by reference to Exhibit 10.1 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-32225).
10.8
Second Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 29, 2007 (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-32225).
10.9Third Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated April 1, 2011 (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-32225).
10.10
Corrected Version dated October 10, 2007, of Amendment and Supplement to Pipeline Lease Agreement effective August 31, 2007 between HEP Pipeline Assets, Limited Partnership and Alon USA, LP (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K dated October 16, 2007, File No. 1-32225)
10.11
Amended and Restated Intermediate Pipelines Agreement, dated June 1, 2009, among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant'sRegistrant’s Current Report on Form 8-K dated June 5, 2009, File No. 1-32225).
10.1210.5
Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.23 of Registrant'sRegistrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-32225).
10.1310.6
Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.24 of Registrant'sRegistrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-32225).
10.1410.7
Tulsa Equipment and Throughput Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Registrant's Current Report on Form 8-K dated August 6, 2009, File No. 1-32225).
10.15
Amendment to Tulsa Equipment and Throughput Agreement, dated December 9, 2010, among Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.28 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-32225).
10.16
Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing - Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.29 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-32225).
10.17
Tulsa Purchase Option Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Registrant'sRegistrant’s Current Report on Form 8-K dated August 6, 2009, File No. 1-32225).


10.8
10.18
Third Amended and Restated Crude Pipelines and Tankage Agreement, dated as of March 12, 2015, by and among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross LLC, HollyFrontier Refining & Marketing LLC, Holly Energy Partners-Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K dated March 16, 2015, File No. 1-32225).
10.1910.9
SecondFirst Amendment to Third Amended and Restated Refined ProductsCrude Pipelines and TerminalsTankage Agreement, dated FebruaryApril 22, 2016,2019, by and among HollyFrontier Navajo Refining LLC, HollyFrontier Woods Cross Refining LLC, HollyFrontier Refining & Marketing LLC, HollyFrontier Corporation, Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and Holly Energy Partners, L.P.HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K dated February 22, 2016, File No. 1-03876).
10.20
Second Amended and Restated Throughput Agreement (Tucson Terminal), dated September 19, 2013, to be effective June 1, 2013, by and among HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C., and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.410.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013,March 31, 2019, File No. 1-32225).
10.21*10.10
EighteenthSecond Amendment to Third Amended and Restated Crude Pipelines and Tankage Agreement dated as of May 26, 2020, by and among HollyFrontier Navajo Refining LLC, HollyFrontier Woods Cross Refining LLC, HollyFrontier Refining & Marketing LLC, Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020, File No. 1-32225).
10.11
Third Amendment to Third Amended and Restated Crude Pipelines and Tankage Agreement entered into as of February 8, 2021, effective as of January 1, 2021, by and among HollyFrontier Navajo Refining LLC, HollyFrontier Woods Cross Refining LLC, HollyFrontier Refining & Marketing LLC, Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.8 of Registrant’s Current Report on Form 8-K dated February 11, 2021, File No. 1-32225).
10.12
Twenty-Second Amended and Restated Omnibus Agreement datedentered into and effective as of January 19, 2018, effective December 8, 2017,March 14, 2022, by and among HollyFrontierHF Sinclair Corporation, Holly Energy Partners, L.P., and certain of their respective subsidiaries.subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K dated March 14, 2022, File No. 1-32225).
10.2210.13
Amended and Restated Limited Liability Company Agreement of HEP UNEV Holdings LLC, dated July 12, 2012, among HEP UNEV Holdings LLC, Holly Energy Partners, L.P. and HollyFrontier Holdings LLC (incorporated by reference to Exhibit 10.7 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-32225).
10.2310.14
Amended and Restated Unloading and Blending Services Agreement, dated January 18, 2017, effective September 16, 2016, by and between HollyFrontier Refining & Marketing LLC, Holly Energy Partners-Operating, L.P. and HEP Refining, L.L.C. (incorporated by reference to Exhibit 10.28 of Registrant'sRegistrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2016, File No. 1-32225).
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10.2410.15
10.16
First Amendment to Eighth Amended and Restated Master Throughput Agreement by and among HollyFrontier Refining & Marketing LLC, Sinclair Oil LLC and Holly Energy Partners – Operating, L.P., dated October 28, 2022 (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2022, File No. 001-32225).
10.17*
Second Amendment to Eighth Amended and Restated Master Throughput Agreement by and between HollyFrontierHF Sinclair Refining & Marketing LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.29, dated as of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2016, File No. 1-32225).22, 2022.
10.2510.18
Construction Payment Agreement, dated as of October 16, 2015, by and between HEP Refining, L.L.C. and HollyFrontier Refining & Marketing LLC (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K dated October 21, 2015, File No. 1-32225).
10.2610.19
ThirdFourth Amended and Restated Services and Secondment Agreement, datedentered into as of October 3, 2016,February 8, 2021, effective as of January 1, 2021, by and among Holly Logistic Services, L.L.C., certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier Corporation (incorporated by reference to Exhibit 10.410.7 of Registrant’s Current Report on Form 8-K dated October 4, 2016,February 11, 2021, File No. 1-32225).
10.2710.20
FourthSeventh Amended and Restated Master Lease Agreement entered into and Access Agreement, datedeffective as of January 18, 2017, effective January 1, 2017,March 14, 2022, by and among certain subsidiaries of HF Sinclair Corporation and Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier Corporation. (incorporated by reference to Exhibit 10.3210.3 of Registrant's AnnualRegistrant’s Current Report on Form 10-K for its fiscal year ended December 31, 2016,8-K dated March 14, 2022, File No. 1-32225).
10.2810.21
First Amendment to Fourth Amended and Restated Master Lease and Access Agreement, dated as of October 13, 2017 by and among certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier Corporation (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017, File No. 1-32225).

10.29
Master Tolling Agreement (Refinery Assets), dated as of November 2, 2015, by and between Frontier El Dorado Refining LLC and Holly Energy Partners-Operating L.P. (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K dated November 3, 2015, File No. 1-32225).
10.3010.22
Amendment to Master Tolling Agreement, dated as of January 1, 2017, by and among Holly Energy Partners-Operating, L.P., HollyFrontier El Dorado Refining LLC and HollyFrontier Woods Cross Refining LLC (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017, File No. 1-32225).

10.3110.23
Amended and Restated Master Tolling Agreement (Operating Assets), dated as of October 3, 2016, by and between HollyFrontier El Dorado Refining LLC, HollyFrontier Woods Cross Refining LLC, Holly Energy Partners-Operating L.P., HollyFrontier Corporation and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K dated October 4, 2016, File No. 1-32225).
10.3210.24
Amendment to Amended and Restated Master Tolling Agreement (Operating Assets), dated as of January 1, 2017, by and among Holly Energy Partners-Operating, L.P., HollyFrontier El Dorado Refining LLC and HollyFrontier Woods Cross Refining LLC (incorporated by reference to Exhibit 10.8 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017, File No. 1-32225.)

10.3310.25
LLC Interest PurchaseSecond Amendment to Amended and Restated Master Tolling Agreement (Operating Assets), dated February 22, 2016,October 29, 2018, by and amongbetween HollyFrontier El Dorado Refining & Marketing LLC, HollyFrontier Corporation, Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.89 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2015, File No. 1-32225).


10.34
Refined Products Terminal Transfer Agreement dated February 22, 2016 by and among HEPWoods Cross Refining Assets, L.P., Holly Energy Partners, L.P., El Paso Logistics LLC HollyFrontier Corporation and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.90 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2015, File No. 1-32225).
10.35Second Amended and Restated Pipelines and Terminals Agreement dated February 22, 2016, by and among HollyFrontier Refining & Marketing LLC, HollyFrontier Corporation, Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.410.7 of Registrant’s Current Report on Form 8-K dated February 22, 2016,November 1, 2018, File No. 1-32225).
10.3610.26
Equity Distribution Agreement, dated May 10, 2016, by and between Holly Energy Partners, L.P., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and Citigroup Global Markets Inc., Goldman, Sachs & Co., and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016, File No. 1-32225).
10.3710.27
Amendment to Equity Distribution Agreement, dated as of July 28, 2017, by and among the Registrant, HEP Logistics Holdings, L.P., Holly Logistics Services, L.L.C. and Citigroup Global Markets Inc., Goldman, Sachs & Co., and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017, File No. 1-32225).

10.3810.28
Pipeline Deficiency Agreement, dated as of August 8, 2016, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant’s Current Report on Form 8-K dated August 10, 2016, File No. 1-32225).
10.3910.29
LLC Interest PurchaseConstruction Payment Agreement, dated as of October 3, 2016,29, 2018, effective December 13, 2017, by and betweenamong HEP Tulsa LLC and HollyFrontier Corporation, HollyFrontier Woods Cross Refining & Marketing LLC Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.110.3 of Registrant’s Current Report on Form 8-K dated October 4, 2016,November 1, 2018, File No. 1-32225).
10.40+10.30
Services Agreement, entered into as of February 8, 2021, effective as of January 1, 2021, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners – Operating, L.P. (incorporated by reference to Exhibit 10.3 of Registrant's Current Report on Form 8-K filed February 11, 2021, File No. 1-32225).
10.31
Asset Lease Agreement, entered into as of February 8, 2021, effective as of January 1, 2021, by and between Cheyenne Logistics LLC and Cheyenne Renewable Diesel Company LLC (incorporated by reference to Exhibit 10.4 of Registrant's Current Report on Form 8-K filed February 11, 2021, File No. 1-32225).
10.32+
Holly Energy Partners, L.P. Long-Term Incentive Plan (as amended and restated effective February 10, 2012) (incorporated by reference to Exhibit 10.1 of Registrant'sRegistrant’s Current Report on Form 8-K dated April 30, 2012, File No. 1-32225).
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10.41+10.33+
First Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan, effective January 16, 2013 (incorporated by reference to Exhibit 10.68 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-32225).
10.42+10.34+
Second Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan, effective October 27, 2021 (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2021, File No. 132225).
10.35+
Form of Holly Energy Partners, L.P. Indemnification Agreement to be entered into with officers and directors of Holly Logistic Services, L.L.C. and its subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2019, File No. 1-32225).
10.36
Letter Agreement entered into on February 8, 2021, effective as of January 1, 2021, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners - Operating, L.P> (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K dated February 18, 2011,11, 2021, File No. 1-32225).
10.43+10.37†
HollyFrontierUnitholders Agreement, dated as of August 2, 2021, by and among Holly Energy Partners, L.P., Holly Logistic
Services, L.L.C., Navajo Pipeline Co., L.P., The Sinclair Companies, and the unitholders set forth on Schedule I
thereto, as may be amended from time to time (incorporated by reference to Exhibit 10.1 of Registrant’s Current
Report on Form 8-K dated August 3, 2021, File No. 1-32225).
10.38+*
HF Sinclair Corporation Executive Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.73 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-32225)(formerly the HF Sinclair Corporation Executive Nonqualified Deferred Compensation Plan).
10.44+10.39+
Holly Energy Partners, L.P. Change in Control Agreement Policy (incorporated by reference to Exhibit 10.3 of Registrant'sRegistrant’s Current Report on Form 8-K dated February 18, 2011, File No. 1-32225).
10.45+10.40+
Form of Change in Control Agreement (incorporated by reference to Exhibit 10.47 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2016, File No. 1-32225).
10.46+10.41+
10.47+10.42+
Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, File No. 1-32225).
10.43+
Form of Phantom Unit Agreement (Employee) (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, File No. 1-32225).
10.44+
Form of Notice of Grant of Phantom Unit Agreement (Employee) (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, File No. 1-32225).
10.45+
Form of Performance Unit Agreement (Executive) (incorporated by reference to Exhibit 10.210.5 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, File No. 1-3225).
10.48*+
Form of Performance Unit Agreement (Executive)
10.49+
Form of Notice of Grant of Restricted Units (Directors) (incorporated by reference to Exhibit 10.105 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2015,September 30, 2021, File No. 1-32225).
10.50+10.46+
Form of Restricted Unit Agreement (Directors) (incorporated by reference to Exhibit 10.107 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2015, File No. 1-32225).
10.51+
Form of Notice of Grant of Restricted Units (Employee) (incorporated by reference to Exhibit 10.52 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2016, File No. 1-32225).
10.52+
Form of RestrictedPhantom Unit Agreement (Employee) (incorporated by reference to Exhibit 10.5310.6 of Registrant’s AnnualQuarterly Report on Form 10-K10-Q for its fiscal yearthe quarterly period ended December 31, 2016,September 30, 2021, File No. 1-32225).
10.53*+10.47+
Form of Notice of Grant of Phantom Units (Employee) (incorporated by reference to Exhibit 10.7 of Registrant’s
Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2021, File No. 1-32225).
10.48+*
Form of Performance Unit Agreement (Executive)
10.49+*
Form of Phantom Unit Agreement.Agreement (Employee)

10.54*+10.50+*
Form of Notice of Grant of Phantom Units.Units (Employee)

21.1*10.51+*
Form of Phantom Unit Agreement (Non-Employee Director Award)
10.52+*
Form of Notice of Grant of Phantom Units (Non-Employee Director Award)
10.53+*
Form of Cash Award Agreement (Employee)
10.54+*
Form of Notice of Grant of Cash Award (Employee)
10.55+
Consulting Agreement between Holly Logistic Services, L.L.C. and Mark Cunningham, effective February 19, 2022 (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K dated October 29, 2021, File No. 1-32225).
10.56
Consulting Agreement, dated as of March 14, 2022, by and between HF Sinclair Corporation and Mark Petersen (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K/A dated March 16, 2022, File No. 1-32225).
10.57+
Holly Energy Partners, L.P. Severance Pay Plan and Summary Plan Description and Form of Participation Agreement (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K dated October 31, 2022, File No. 1-32225).
10.58+
Mutual Separation Agreement and Release of Claims by and among HF Sinclair Corporation, HollyFrontier Corporation, Holly Logistic Services, L.L.C., HollyFrontier Payroll Services, Inc., and Holly Energy Partners, L.P., on behalf of themselves and their respective parents, subsidiaries and affiliates and Richard Voliva, dated September 15, 2022 (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2022, File No. 001-32225).
21.1*
Subsidiaries of Registrant.
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22.1*
Subsidiary Guarantors and Issuers of Guaranteed Securities and Affiliates whose Securities Collateralize Securities of the Registrant.
23.1*
Consent of Independent Registered Public Accounting Firm.
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**
32.1**
Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
101++The following financial information from Holly Energy Partners, L.P.’s Annual Report on Form 10-K for its fiscal year ended December 31, 2017,2022, formatted inas inline XBRL (Extensible(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) Consolidated Statement of Partners’ Equity, and (vi) Notes to Consolidated Financial Statements. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
104++Cover page Interactive Data File (formatted as inline XBRL and contained in exhibit 101).



* Filed herewith.
** Furnished herewith.
+ Constitutes management contracts or compensatory plans or arrangements.
++ Filed electronically herewith.

† Schedules and certain exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K.  The registrant agrees     


to furnish supplementally a copy of the omitted schedules and exhibits to the SEC upon request.

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HOLLY ENERGY PARTNERS, L.P.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities 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)
By: HEP LOGISTICS HOLDINGS, L.P.
its General Partner
By: HOLLY LOGISTIC SERVICES, L.L.C.
its General Partner
Date: February 28,2023/s/ Michael C. Jennings
Michael C. Jennings
Chief Executive Officer and President
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: February 21, 2018/s/ George J. Damiris
George J. Damiris
Chief Executive Officer





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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: February 28,2023/s/ Michael C. Jennings
Date: February 21, 2018/s/ George J. DamirisMichael C. Jennings
George J. Damiris
President, Chief Executive Officer, President and DirectorChairperson of the Board
Date: February 21, 201828,2023/s/ Richard L. Voliva IIIJohn Harrison
Richard L. Voliva IIIJohn Harrison
ExecutiveSenior Vice President, and Chief Financial Officer and Treasurer
(Principal Financial Officer)
Date: February 21, 201828,2023/s/ Kenneth P. Norwood
Kenneth P. Norwood
Vice President and Controller
(Principal Accounting Officer)
Date: February 21, 201828,2023/s/ Michael C. Jennings
Michael C. Jennings

Chairman of the Board
Date: February 21, 2018/s/ Larry R. Baldwin
Larry R. Baldwin
Director
Date: February 21, 201828,2023/s/ Christine B. LaFollette
Christine B. LaFollette
Director
Date: February 28,2023/s/ James H. Lee
James H. Lee
Director
Date: February 21, 201828,2023/s/ R. Kevin HardageEric L. Mattson
R. Kevin HardageEric L. Mattson
Director
Date: February 28,2023/s/ Mark A. Petersen
Mark A. Petersen
Director



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