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, 20172020
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 1-3876
 _________________________________________________________________
HOLLYFRONTIER CORPORATION
(Exact name of registrant as specified in its charter)

Delaware75-1056913
(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
(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 Stock $0.01 par valueHFCNew York Stock Exchange
Common Stock, $0.01 par value registered on the New York Stock Exchange.

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 Webweb 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.       ¨☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,”company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerý☒Accelerated filer¨☐Non-accelerated filer¨☐Smaller reporting company¨☐
Emerging growth company¨☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐
Indicate by check mark whether the registrant 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. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨☐ No  ý☒
On June 30, 2017,2020, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the Common Stock, par value $0.01$0.01 per share, held by non-affiliates of the registrant was approximately $4.5$4.3 billion, based upon the closing price on the New York Stock Exchange on such date. (This is not deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.)
177,363,228162,414,838 shares of Common Stock, par value $.01$.01 per share, were outstanding on February 16, 2018.2021.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 9, 2018,12, 2021, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2017,2020, are incorporated by reference in Part III.


Table of Content

TABLE OF CONTENTS




ItemPage
PART I
Item
Forward-Looking Statements
Page
3
PART I
Forward-Looking StatementsDefinitions
34
Definitions
4
1 and 2. Business and propertiesProperties
6
1A. Risk Factors
2223
1B. Unresolved staff commentsStaff Comments
3240
3. Legal proceedingsProceedings
3341
4. Mine safety disclosuresSafety Disclosures
3343
PART II
5. Market for Registrant's common equity, related stockholder mattersCommon Equity, Related Stockholder Matters and issuer purchasesIssuer Purchases of equity securitiesEquity Securities
3444
6. Selected financial dataFinancial Data
3545
7. Management's discussionDiscussion and analysisAnalysis of financial conditionFinancial Condition and resultsResults of operationsOperations
3646
7A. Quantitative and qualitative disclosuresQualitative Disclosures about market riskMarket Risk
5161
Reconciliations to amounts reported under generally accepted accounting principlesAmounts Reported Under Generally Accepted Accounting Principles
5161
8. Financial statementsStatements and supplementary dataSupplementary Data
5363
9. Changes in and disagreementsDisagreements with accountantsAccountants on accountingAccounting and financial disclosureFinancial Disclosure
98115
9A. Controls and proceduresProcedures
98115
9B. Other informationInformation
98115
PART III
10. Directors, executive officersExecutive Officers and corporate governanceCorporate Governance
98115
11. Executive compensationCompensation
98115
12. Security ownershipOwnership of certain beneficial ownersCertain Beneficial Owners and managementManagement and related stockholder mattersRelated Stockholder Matters
98115
13. Certain relationshipsRelationships and related transactions,Related Transactions, and director independenceDirector Independence
99116
14. Principal accounting feesAccounting Fees and servicesServices
99116
PART IV
15. Exhibits, financial statement schedulesFinancial Statement Schedules
99116
Index to exhibits
100
Signatures
106122

2
Table of Content

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, those under “Business and Properties” in Items 1 and 2, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. Forward-looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “should,” “would,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on management's beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. 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. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors including, but not limited to:


•the extraordinary market environment and effects of the COVID-19 pandemic, including a significant decline in demand for refined petroleum products in markets we serve;
•risks and uncertainties with respect to the actions of actual or potential competitive suppliers and transporters of refined petroleum products or lubricant and specialty products in our markets;
the demand for and supply of crude oil and refined products;
•the spread between market prices for refined products and market prices for crude oil;
•the possibility of constraints on the transportation of refined products or lubricant and specialty products;
•the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines;pipelines, whether due to infection in the workforce or in response to reductions in demand;
•the effects of current and future governmental and environmental 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;
•the availability and cost of our financing;
•the effectiveness of our capital investments and marketing strategies;
•our efficiency in carrying out and consummating construction projects;projects, including our ability to complete announced capital projects, such as the conversion of the Cheyenne Refinery to a renewable diesel facility and the construction of the Artesia renewable diesel unit and pretreatment unit, on time and within budget;
•our ability to timely obtain or maintain permits, including those necessary for operations or capital projects,
•our ability to acquire refined or lubricant product operations or pipeline and terminal operations on acceptable terms and to integrate any existing or future acquired operations;
•the possibility of terrorist attacksor cyberattacks and the consequences of any such attacks;
•general economic conditions;conditions, including uncertainty regarding the timing, pace and extent of an economic recovery in the United States;
•continued deterioration in gross margins or a prolonged economic slowdown due to the COVID-19 pandemic which could result in an impairment of goodwill and / or additional long-lived asset impairments; and
•other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange CommissionSEC 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 risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 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.




3
Table of Content

DEFINITIONS


Within this report, the following terms have these specific meanings:
“Alkylation” means the reaction of propylene or butylene (olefins) with isobutane to form an iso-paraffinic gasoline (inverse of cracking).


“Aromatic oil” is long chain oil that is highly aromatic in nature and is used to manufacture tires and industrial rubber products and in the production of specialty asphalt.


“BPD” means the number of barrels per calendar day of crude oil or petroleum products.
“BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum products.


“Base oil” is a lubricant grade oil initially produced from refining crude oil or through chemical synthesis that is used in producing lubricant products such as lubricating greases, motor oil and metal processing fluids.


“Biodiesel” means ana clean alternative fuel produced from renewable biological resources.


“Black wax crude oil” is a low sulfur, low gravity crude oil produced in the Uintah Basin in Eastern Utah that has certain characteristics that require specific facilities to transport, store and refine into transportation fuels.


“Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is a primary source of hydrogen for the refinery.
“Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules.


“Crude oil distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the vapor slightly above atmospheric pressure turning it back to liquid in order to purify, fractionate or form the desired products.


“Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline.


“FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.


“Gas oil” is a group of petroleum distillation products having boiling points between kerosene and lubricating oil and is used as fuel in construction and agricultural machinery.


“Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and a catalyst at relatively high temperatures.


“Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization processes.


“HF alkylation” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.
“Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.


“LPG” means liquid petroleum gases.


“Lubricant” or “lube” means a solvent neutral paraffinic product used in commercial heavy duty engine oils, passenger car oils and specialty products for industrial applications such as heat transfer, metalworking, rubber and other general process oil.


4
Table of Content

“MSAT2” means Control of Hazardous Air Pollutants from Mobile Sources, a rule issued by the U.S. Environmental Protection Agency to reduce hazardous emissions from motor vehicles and motor vehicle fuels.


“MEK” means a lube process that separates waxy oil from non-waxy oils using methyl ethyl ketone as a solvent.


“MMBTU” means one million British thermal units.


“Natural gasoline” means a low octane gasoline blend stock that is purchased and used to blend with other high octane stocks produced to make various grades of gasoline.


“Paraffinic oil” is a high paraffinic, high gravity oil produced by extracting aromatic oils and waxes from gas oil and is used in producing high-grade lubricating oils.


“Rack back” represents the portion of our Lubricants and Specialty Products business operations that entails the processing of feedstocks into base oils.


“Rack forward” represents the portion of our Lubricants and Specialty Products business operations that entails the processing of base oils into finished lubricants and the packaging, distribution and sale to customers.


“Refinery gross margin” means the difference between average net sales price and average cost per barrel sold. This does not include the associated depreciation and amortization costs.


“Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks while producing hydrogen in the process.


“Renewable diesel” means a diesel fuel derived from vegetable oils or animal fats that is produced through various processes, most commonly through hydrotreating, reacting the feedstock with hydrogen under temperatures and pressure in the presence of a catalyst.

“RINs” means renewable identification numbers and refers to serial numbers assigned to credits generated from renewable fuel production under the Environmental Protection Agency’s Renewable Fuel Standard (“RFS”) regulations, which require blending renewable fuels into the nation's fuel supply. In lieu of blending, refiners may purchase these transferable credits in order to comply with the regulations.


“Roofing flux” is produced from the bottom cut of crude oil and is the base oil used to make roofing shingles for the housing industry.


“ROSE,” or “Solvent deasphalter / residuum oil supercritical extraction,” means a refinery unit that uses a light hydrocarbon like propane or butane to extract non-asphaltene heavy oils from asphalt or atmospheric reduced crude. These deasphalted oils are then further converted to gasoline and diesel in the FCC process. The remaining asphaltenes are either sold, blended to fuel oil or blended with other asphalt as a hardener.


“Scanfiner” is a refinery unit that removes sulfur from gasoline to produce low sulfur gasoline blendstock.


“Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet crude oil” means crude oil containing quantities of sulfur equal to or less than 0.4 percent by weight.


“Vacuum distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the vapor below atmospheric pressure turning it back to a liquid in order to purify, fractionate or form the desired products.


“White oil” is an extremely pure, highly-refined petroleum product that has a wide variety of applications ranging from pharmaceutical to cosmetic products.
“WTI” means West Texas Intermediate and is a grade of crude oil used as a common benchmark in oil pricing. WTI is a sweet crude oil and has a relatively low density.


5
Table of Content

Items 1 and 2. Business and Properties




COMPANY OVERVIEW


References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission's (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person, with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.


We are principally an independent petroleum refiner that produces high-value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We were incorporated in Delaware in 1947 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.hollyfrontier.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A print 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 SEC filings is available on our website under the Investor Relations tab. Also available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, Nominating / Corporate Governance Committee Charter, Environmental, Health, Safety, and Public Policy Committee Charter and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Director,Vice President, Investor Relations at the above address. Our Code of Business Conduct and Ethics applies to all of our officers, employees and directors, including our principal executive officer, principal financial officer and principal accounting officer. Our common stock is traded on the New York Stock Exchange under the trading symbol “HFC.”


In November 2019, we announced our plans to construct a new renewable diesel unit (“RDU”) at our Artesia facility. The RDU will have a production capacity of approximately 120 million gallons a year and allow us to process soybean oil and other renewable feedstocks into renewable diesel. This investment will provide us the opportunity to meet the demand for low-carbon fuels while covering the cost of our annual RINs purchase obligation under current market conditions.

In the third quarter of 2020, we permanently ceased petroleum refining operations at our Cheyenne Refinery and subsequently began converting certain assets at our Cheyenne Refinery to renewable diesel production. The Cheyenne RDU will have a production capacity of approximately 90 million gallons a year. This decision was primarily based on a positive outlook in the market for renewable diesel and the expectation that future free cash flow generation at our Cheyenne Refinery would be challenged due to lower gross margins resulting from the economic impact of the COVID-19 pandemic and compressed crude differentials due to dislocations in the crude oil market. Additional factors included uncompetitive operating and maintenance costs forecasted for our Cheyenne Refinery and the anticipated loss of the Environmental Protection Agency’s (“EPA”) small refinery exemption.

Additionally, we are constructing a pre-treatment unit (“PTU”) at our Artesia facility that will provide feedstock flexibility for both our Artesia and Cheyenne RDUs. The RDUs and PTU, along with corresponding rail infrastructure and storage tanks, are estimated to have a total capital cost of $650 million to $750 million. The RDUs are expected to be completed in the first quarter of 2022 and the PTU in the first half of 2022.

On November 12, 2018, we entered into an equity purchase agreement to acquire 100% of the issued and outstanding capital stock of Sonneborn US Holdings Inc. and 100% of the membership rights in Sonneborn Coöperatief U.A. (collectively, “Sonneborn”). The acquisition closed on February 1, 2019. Cash consideration paid was $662.7 million. Sonneborn is a producer of specialty hydrocarbon chemicals such as white oils, petrolatums and waxes with manufacturing facilities in the United States and Europe.

On July 10, 2018, we entered into a definitive agreement to acquire Red Giant Oil Company LLC (“Red Giant Oil”), a privately-owned lubricants company. The acquisition closed on August 1, 2018. Cash consideration paid was $54.2 million. Red Giant Oil is one of the largest suppliers of locomotive engine oil in North America and is headquartered in Council Bluffs, Iowa.

6
Table of Content
On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc.,we entered into a share purchase agreement with Suncor Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of Petro-Canada Lubricants Inc. (“PCLI”). The acquisition closed on February 1, 2017. Cash consideration paid was $862.1 million, or $1.125 billion in Canadian dollars.

PCLI, is located in Mississauga, Ontario, and is the largest producer of base oils in Canada with a plant having 15,600 BPD of lubricant production capacity and is one of the largest manufacturermanufacturers of high margin Group III base oils in North America. The facility is downstream integrated from base oils to finished lubricants and produces a broad spectrum of specialty lubricants and white oils that are distributed to end customers worldwide. The acquisition brings to HollyFrontier industry-leading product innovation and research and development capabilities, a global sales and distribution network and a strong brand portfolio recognized globally. With this transaction, we have also acquired a perpetual exclusive license to use the Petro-Canada trademark in association with the lubricant products. With the addition of PCLI, we became the fourth largest lubricants producer in North America with a capacity of 28,000 BPD, approximately 10% of North American production.


As of December 31, 2017,2020, we:
•owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two refinery facilities located in Tulsa, Oklahoma (collectively, the “Tulsa Refineries”), a refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”) and a refinery in Woods Cross, Utah (the “Woods Cross Refinery”);
•owned a facility in Cheyenne, Wyoming, which operated as a petroleum refinery until early August 2020, at which time its assets began to be converted to renewable diesel production (the “Cheyenne Refinery”);
•owned and operated PCLI located in Mississauga, Ontario, which produces base oils and other specialized lubricant products;
•owned and operated Sonneborn with manufacturing facilities in Petrolia, Pennsylvania and the Netherlands, which produce specialty lubricant products such as white oils, petrolatums and waxes;
•owned and operated Red Giant Oil, which supplies locomotive engine oil and has storage and distribution facilities in Iowa and Wyoming, along with a blending and packaging facility in Texas;
•owned and operated HollyFrontier Asphalt Company LLC (“HFC Asphalt”), which operates various asphalt terminals in Arizona, New Mexico and Oklahoma; and
•owned a 59%57% limited partner interest and a non-economic general partner interest in HEP.
HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and refinery processing units that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States.


HEP is a variable interest entity (“VIE”) as defined under U.S. generally accepted accounting principles (“GAAP”). Information on HEP's assets and acquisitions completed between 2013 and 2017in the past three years can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”

Table of Content


Our operations are currently organized into three reportable segments, Refining, Lubricants and Specialty Products and HEP. The Refining segment includes the operations of our El Dorado, Tulsa, Navajo Cheyenne and Woods Cross Refineries and HFC Asphalt. The Lubricants and Specialty Products segment includes the operations of our Petro-Canada Lubricants business, Red Giant Oil and Sonneborn in addition to specialty lubricant products produced at our Tulsa Refinery. The HEP segment involves all of the operations of HEP. See Note 20 “Segment Information” in the Notes to Consolidated Financial Statements for additional information on our reportable segments.




REFINERY OPERATIONS


Our refinery operations serve the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States. We own and operate fivefour complex refineries having a combined crude oil processing capacity of 457,000405,000 barrels per stream day. Each of our refineries has the complexity to convert discounted, heavy and sour crude oils into a high percentage of gasoline, diesel and other high-value refined products.


The tables presented below and elsewhere in this discussion of our refinery operations set forth information, including non-GAAP performance measures, about our refinery operations. The cost of products and refinery gross and net operating margins do not include the non-cash effects of long-lived asset impairment charges, lower of cost or market inventory valuation adjustments and depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


During
7
Table of Content
As of December 31, 2020, our refinery operations included the fourthEl Dorado, Tulsa, Navajo and Woods Cross Refineries. In the third quarter of 2017,2020, we revised the followingpermanently ceased petroleum refining segment operating data computations: refinery gross margin; net operating margin;operations at our Cheyenne Refinery and operating expensessubsequently began converting certain assets at our Cheyenne Refinery to better align with similar measurements provided by other companies in our industry and to facilitate comparisonrenewable diesel production. The disaggregation of our refining performance relativegeographic operating data is presented in two regions, Mid-Continent and West, to best reflect the economic drivers of our peers. Effective with this change, these measurements are now inclusiverefining operations. The Mid-Continent region will continue to be comprised of all refining segment activities including HFC Asphalt operationsthe El Dorado and revenuesTulsa Refineries, and costs related to products purchased for resalethe new West region will be comprised of the Navajo and excess crude oil sales.Woods Cross Refineries. All prior period geographic operating data included below has been retrospectively adjusted to reflect the revised regional groupings.
Years Ended December 31,
202020192018
Consolidated
Crude charge (BPD) (1)
365,190 388,860 384,380 
Refinery throughput (BPD) (2)
395,080 417,570 413,780 
Sales of produced refined products (BPD) (3)
391,670 414,370 408,390 
Refinery utilization (4)
90.2 %96.0 %94.9 %
Average per produced barrel sold (5)
Refinery gross margin$7.29 $15.92 $16.50 
Refinery operating expenses (6)
6.05 6.12 6.06 
Net operating margin$1.24 $9.80 $10.44 
Refinery operating expenses per throughput barrel (7)
$6.00 $6.07 $5.98 
Feedstocks:
Sweet crude oil48 %45 %44 %
Sour crude oil29 %34 %35 %
Heavy sour crude oil11 %10 %10 %
Black wax crude oil4 %4 %4 %
Other feedstocks and blends8 %7 %7 %
Total100 %100 %100 %

(1)Crude charge represents the barrels per day of crude oil processed at our current presentation.refineries.
(2)Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.
(3)Represents barrels sold of refined products produced at our refineries (including HFC Asphalt) and does not include volumes of refined products purchased for resale or volumes of excess crude oil sold.
(4)Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity is 405,000 BPSD.
(5)Represents average amount per produced barrel sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
(6)Represents total Mid-Continent and West regions operating expenses, exclusive of long-lived asset impairment charges and depreciation and amortization, divided by sales volumes of refined products produced at our refineries.
(7)Represents total Mid-Continent and West regions operating expenses, exclusive of long-lived asset impairment charges and depreciation and amortization, divided by refinery throughput.

8
  Years Ended December 31,
  2017 2016 2015
Consolidated      
Crude charge (BPD) (1)
 438,800
 423,910
 432,560
Refinery throughput (BPD) (2)
 472,010
 457,480
 463,580
Sales of produced refined products (BPD) (3)
 452,270
 440,640
 442,650
Refinery utilization (4)
 96.0% 92.8% 97.6%
Average per produced barrel sold (5)
      
Refinery gross margin (6)
 $11.56
 $8.16
 $15.88
Refinery operating expenses (7)
 6.10
 5.64
 5.82
Net operating margin $5.46
 $2.52
 $10.06
       
Refinery operating expenses per throughput barrel (8)
 $5.84
 $5.43
 $5.56
       
Feedstocks:      
Sweet crude oil 48% 48% 51%
Sour crude oil 25% 26% 25%
Heavy sour crude oil 16% 16% 15%
Black wax crude oil 4% 3% 2%
Other feedstocks and blends 7% 7% 7%
Total 100% 100% 100%

(1)Crude charge represents the barrels per day of crude oil processed at our refineries.
(2)Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.
(3)Represents barrels sold of refined products produced at our refineries (including HFC Asphalt) and does not include volumes of refined products purchased for resale or volumes of excess crude oil sold.
(4)Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2016, our consolidated crude capacity increased from 443,000 BPSD to 457,000 BPSD upon completion of our Woods Cross Refinery expansion project.
Table of Content

(5)Represents average amount per produced barrel sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
(6)Excludes lower of cost or market inventory valuation adjustments that increased refinery gross margin by $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016, respectively, and decreased refinery gross margin by $227.0 million for the year ended December 31, 2015.
(7)Represents total refining segment operating expenses, exclusive of depreciation and amortization, divided by sales volumes of refined products produced at our refineries.
(8)Represents total refining segment operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.

Products and Customers
Set forth below is information regarding refined product sales:
Years Ended December 31,
202020192018
Consolidated
Sales of refined products:
Gasolines54 %52 %52 %
Diesel fuels34 %34 %34 %
Jet fuels3 %4 %4 %
Fuel oil1 %2 %2 %
Asphalt4 %3 %3 %
Base oils2 %2 %3 %
LPG and other2 %3 %2 %
Total100 %100 %100 %
  Years Ended December 31,
  2017 2016 2015
Consolidated      
Sales of refined products:      
Gasolines 52% 52% 52%
Diesel fuels 34% 34% 35%
Jet fuels 4% 4% 4%
Fuel oil 2% 2% 1%
Asphalt 4% 3% 3%
Base oils 2% 3% 2%
LPG and other 2% 2% 3%
Total 100% 100% 100%


Light products are shipped to customers via product pipelines or are available for loading at our refinery truck facilities and terminals. Light products are also made available to customers at various other locations via exchange with other parties.


Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for commercial airline use. Base oils are intercompany sales to our Lubricants and Specialty lubricant products are sold in both commercial and specialty markets.Products segment. LPG's are sold to LPG wholesalers and LPG retailers. We produce and purchase asphalt products that are sold to governmental entities, paving contractors or manufacturers. Asphalt is also blended into fuel oil and is either sold locally or is shipped to the Gulf Coast. See Note 21 “Significant Customers”5 “Revenues” in the Notes to Consolidated Financial Statements for additional information on our significant customers.




Mid-Continent Region (El Dorado and Tulsa Refineries)


Facilities
The El Dorado Refinery is a high-complexity coking refinery with a 135,000 barrels per stream day processing capacity and the ability to process significant volumes of heavy and sour crudes. The integrated refining processes at the Tulsa West and East refinery facilities provide us with a highly complex refining operation having a combined crude processing rate of approximately 125,000 barrels per stream day.

Table of Content


The following table sets forth information about our Mid-Continent region operations, including non-GAAP performance measures.
Years Ended December 31,
202020192018
Mid-Continent Region (El Dorado and Tulsa Refineries)
Crude charge (BPD) (1)
241,140 254,010 249,240 
Refinery throughput (BPD) (2)
257,030 268,500 264,730 
Sales of produced refined products (BPD) (3)
248,320 259,310 255,800 
Refinery utilization (4)
92.7 %97.7 %95.9 %
Average per produced barrel sold (5)
Refinery gross margin$5.17 $13.71 $14.44 
Refinery operating expenses (6)
5.46 5.77 5.51 
Net operating margin$(0.29)$7.94 $8.93 
Refinery operating expenses per throughput barrel (7)
$5.27 $5.58 $5.33 
  Years Ended December 31,
  2017 2016 2015
Mid-Continent Region (El Dorado and Tulsa Refineries)      
Crude charge (BPD) (1)
 261,380
 262,170
 263,340
Refinery throughput (BPD) (2)
 277,940
 280,920
 277,260
Sales of produced refined products (BPD) (3)
 260,800
 262,300
 259,290
Refinery utilization (4)
 100.5% 100.8% 101.3%
       
Average per produced barrel sold (5)
      
Refinery gross margin (6)
 $9.91
 $7.44
 $15.02
Refinery operating expenses (7)
 5.15
 4.73
 5.00
Net operating margin $4.76
 $2.71
 $10.02
       
Refinery operating expenses per throughput barrel (8)
 $4.83
 $4.42
 $4.68

  Years Ended December 31,
  2017 2016 2015
Mid-Continent Region (El Dorado and Tulsa Refineries)      
Feedstocks:      
Sweet crude oil 61% 58% 59%
Sour crude oil 17% 18% 21%
Heavy sour crude oil 16% 17% 15%
Other feedstocks and blends 6% 7% 5%
Total 100% 100% 100%


Footnote references are provided under our Consolidated Refinery Operating Data table on page 7.8.


9
Table of Content
Years Ended December 31,
202020192018
Mid-Continent Region (El Dorado and Tulsa Refineries)
Feedstocks:
Sweet crude oil58 %55 %54 %
Sour crude oil19 %24 %24 %
Heavy sour crude oil17 %16 %16 %
Other feedstocks and blends6 %5 %6 %
Total100 %100 %100 %

The El Dorado Refinery is located on 1,100 acres south of El Dorado, Kansas and is a fully integrated refinery. The principal processing units at the El Dorado Refinery consist of crude and vacuum distillation; hydrodesulfurization of naphtha, kerosene, diesel, and gas oil streams; isomerization; catalytic reforming; aromatics recovery; catalytic cracking; alkylation; delayed coking; hydrogen production; and sulfur recovery. Refining operations began at the site in 1917 and the operating units now present include both newly constructed units and older units that have been upgraded over the years.


The Tulsa West facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal processing units at the Tulsa West facility consist of crude and vacuum distillation (with light ends recovery), naphtha hydrodesulfurization, propane de-asphalting, lubes extraction, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s.


The Tulsa East facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal processprocessing units at the Tulsa East facility consist of crude and vacuum distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units.


Markets and Competition
The primary markets for the El Dorado Refinery's refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. We ship product via the NuStar Pipeline Operating Partnership L.P. Pipeline to the northern Plains States, via the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline to Denver, Colorado, and on the Magellan mid-continent pipeline to the Plains States. Additionally, HEP's on-site truck and rail racks facilitate access to local refined product markets.

Table of Content


The El Dorado Refinery faces competition from other Plains States and Mid-Continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Our Gulf Coast competitors typically have lower production costs due to greater economies of scale; however, they incur higher refined product transportation costs, which allows the El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with Gulf Coast refineries.


The Tulsa Refineries serve the Mid-Continent geographic region of the United States. Distillates and gasolines are primarily delivered from the Tulsa Refineries to market via pipelines owned and operated by Magellan. These pipelines connect the refinery to distribution channels throughout Colorado, Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, HEP's on-site truck and rail racks facilitate access to local refined product markets.

We have an offtake agreement through November 2019 with an affiliate of Sinclair whereby Sinclair purchases 45,000 to 50,000 BPD of gasoline and distillate products at market prices from us to supply its branded and unbranded marketing network throughout the Midwest. Upon expiration, the offtake agreement can be renewed by Sinclair for an additional five-year term. For the year ended December 31, 2017, sales to Sinclair represented approximately 21% of the Tulsa Refineries’ total sales and 8% of our total consolidated sales.


The Tulsa Refineries’ principal customers for conventional gasoline include Sinclair, other refiners, convenience store chains, independent marketers and retailers. Sinclair, truckTruck stop operators and railroads are the primary diesel customers. Jet fuel is sold primarily for commercial use. The refinery's asphalt and roofing flux products are sold via truck or railcar directly from the refineries or to customers throughout the Mid-Continent geographic region primarily to paving contractors and manufacturers of roofing products.


For the year ended December 31, 2017, sales to Shell Oil represented approximately 12%
10
Table of our Mid-Continent refineries’ total sales and 9% of our total consolidated sales. We have a sales agreement with an affiliate of Shell Oil under which Shell Oil purchases gasoline and diesel production of the El Dorado Refinery and Tulsa Refineries at market prices through October 2018 primarily to support its branded marketing network.Content

Products
Set forth below is information regarding refined product sales attributable to our Mid-Continent region:
Years Ended December 31,
202020192018
Mid-Continent Region (El Dorado and Tulsa Refineries)
Sales of refined products:
Gasolines52 %51 %51 %
Diesel fuels34 %32 %33 %
Jet fuels4 %7 %6 %
Fuel oil1 %1 %1 %
Asphalt3 %3 %3 %
Base oils4 %4 %4 %
LPG and other2 %2 %2 %
Total100 %100 %100 %
  Years Ended December 31,
  2017 2016 2015
Mid-Continent Region (El Dorado and Tulsa Refineries)      
Sales of refined products:      
Gasolines 50% 50% 50%
Diesel fuels 33% 33% 33%
Jet fuels 7% 7% 7%
Fuel oil 1% 1% 1%
Asphalt 3% 3% 2%
Base oils 4% 4% 4%
LPG and other 2% 2% 3%
Total 100% 100% 100%


Crude Oil and Feedstock Supplies
Both of our Mid-Continent Refineries are connected via pipeline to Cushing, Oklahoma, a significant crude oil pipeline trading and storage hub. The El Dorado Refinery and the Tulsa Refineries are located approximately 125 miles and 50 miles, respectively, from Cushing, Oklahoma. Local pipelines provide direct access to regional Oklahoma crude production as well as access to United States onshore and Canadian crudes. The proximity of the refineries to the Cushing pipeline and storage hub provides the flexibility to optimize their crude slate with a wide variety of crude oil supply options. Additionally, we have transportation service agreements to transport Canadian crude oil on the Spearhead and Keystone Pipelines, enabling us to transport Canadian crude oil to Cushing for subsequent shipment to either of our Mid-Continent Refineries.


We also purchase isobutane, natural gasoline, butane and other feedstocks for processing at our Mid-Continent Refineries. The El Dorado Refinery is connected to Conway, Kansas, a major gas liquids trading and storage hub, via the Oneok Pipeline. From time to time, other feedstocks such gas oil, naphtha and light cycle oil are purchased from other refiners for use at our refineries.




Table of Content

SouthwestWest Region (Navajo Refinery)and Woods Cross Refineries)


Facilities
The Navajo Refinery has a crude oil processing capacity of 100,000 barrels per stream day and has the ability to process sour crude oils into high-value light products such as gasoline, diesel fuel and jet fuel.


The Woods Cross Refinery has a crude oil processing capacity of 45,000 barrels per stream day and processes regional sweet and black wax crude into high-value light products.

The following table sets forth information about our SouthwestWest region operations, including non-GAAP performance measures.
Years Ended December 31,
 Years Ended December 31,202020192018
 2017 2016 2015
Southwest Region (Navajo Refinery)      
West Region (Navajo and Woods Cross Refineries)West Region (Navajo and Woods Cross Refineries)
Crude charge (BPD) (1)
 100,040
 98,090
 100,450
Crude charge (BPD) (1)
124,050 134,850 135,140 
Refinery throughput (BPD) (2)
 109,280
 107,690
 111,840
Refinery throughput (BPD) (2)
138,050 149,070 149,050 
Sales of produced refined products (BPD) (3)
 111,630
 111,390
 114,790
Sales of produced refined products (BPD) (3)
143,350 155,060 152,590 
Refinery utilization (4)
 100.0% 98.1% 100.5%
Refinery utilization (4)
85.6 %93.0 %93.2 %
      
Average per produced barrel sold (5)
      
Average per produced barrel sold (5)
Refinery gross margin (6)
 $12.40
 $9.49
 $16.34
Refinery operating expenses (7)
 5.20
 5.05
 5.24
Refinery gross marginRefinery gross margin$10.97 $19.62 $19.96 
Refinery operating expenses (6)
Refinery operating expenses (6)
7.07 6.69 6.99 
Net operating margin $7.20
 $4.44
 $11.10
Net operating margin$3.90 $12.93 $12.97 
      
Refinery operating expenses per throughput barrel (8)
 $5.31
 $5.23
 $5.38
Refinery operating expenses per throughput barrel (7)
Refinery operating expenses per throughput barrel (7)
$7.34 $6.96 $7.15 
  Years Ended December 31,
  2017 2016 2015
Southwest Region (Navajo Refinery)      
Feedstocks:      
Sweet crude oil 25% 28% 36%
Sour crude oil 66% 63% 54%
Other feedstocks and blends 9% 9% 10%
Total 100% 100% 100%


Footnote references are provided under our Consolidated Refinery Operating Data table on page 7.page 8.


11
Table of Content
Years Ended December 31,
202020192018
West Region (Navajo and Woods Cross Refineries)
Feedstocks:
Sweet crude oil30 %26 %27 %
Sour crude oil49 %52 %52 %
Black wax crude oil11 %12 %12 %
Other feedstocks and blends10 %10 %9 %
Total100 %100 %100 %

The Navajo Refinery's Artesia, New Mexico facility is located on a 561-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, mild hydrocracking, isomerization, sulfur recovery and product blending units. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970.


The Artesia facility is operated in conjunction with a refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970.units. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of three intermediate pipelines owned by HEP. These products are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Navajo Refinery facilities is 100,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.


The Woods Cross Refinery facility is located on a 200-acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. The facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 45,000 BPSD capacity.

Markets and Competition
The Navajo Refinery primarily serves the southwestern United States market, including the metropolitan areas of El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and portions of northern Mexico. Our products are shipped through HEP's pipelines from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Magellan and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan's subsidiary, SFPP, L.P. (“SFPP”). In addition, petroleum products from the Navajo Refinery are transported to markets in northwest New Mexico, to Moriarty, New Mexico, near Albuquerque, via HEP's pipelines running from Artesia to San Juan County, New Mexico, and to Bloomfield, New Mexico. We have refined product storage through our pipelines and terminals agreement with HEP at terminals in Tucson, Arizona, and Artesia and Moriarty, New Mexico.

Table of Content

El Paso Market
The El PasoWoods Cross Refinery's primary market for refined productsis Utah, which is currently supplied by a number of area and Gulf Coastlocal refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between Phillips 66 and Cenovus Energy), Valero, Delek and Andeavor. Pipelines serving this market are owned by Magellan, NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines.

Arizona Market
The Arizona market forPioneer Pipeline. It also supplies a small percentage of the refined products is currently supplied by a number of refiners via pipelinesconsumed in the combined Idaho, Wyoming, eastern Washington and trucks. Refiners include companies located in west Texas, eastern New Mexico, northern New Mexico, the Gulf Coast and the West Coast. Magellan's pipeline systems deliverNevada markets. Our Woods Cross Refinery ships refined products from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market.

New Mexico Markets
The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Andeavor, Delek and WRB.

We useover a common carrier pipeline out of El Pasosystem owned by Andeavor Logistics Northwest Pipelines LLC to serve the Albuquerque market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexiconumerous terminals, including HEP's terminal at Spokane, Washington and the Albuquerque vicinityto third-party terminals at Pocatello and Bloomfield, New Mexico. The lease agreement currently runs through 2026,Boise, Idaho and HEP has options to renew for one additional ten-year period. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipelinePasco, Washington as well as terminalling facilities in Moriarty, which is 40 miles east of Albuquerque. This facility permits us to ship light products toCedar City, Utah and Las Vegas, Nevada via the Albuquerque and Santa Fe, New Mexico areas. In addition, we serve southern Colorado and northern Arizona primarily out of a terminal in Bloomfield, New Mexico, which is owned by Andeavor.UNEV Pipeline.


Products
Set forth below is information regarding refined product sales attributable to our SouthwestWest region:
Years Ended December 31,
202020192018
West Region (Navajo and Woods Cross Refineries)
Sales of refined products:
Gasolines56 %53 %53 %
Diesel fuels35 %37 %38 %
Fuel oil3 %3 %3 %
Asphalt4 %4 %3 %
LPG and other2 %3 %3 %
Total100 %100 %100 %

12
  Years Ended December 31,
  2017 2016 2015
Southwest Region (Navajo Refinery)      
Sales of refined products:      
Gasolines 51% 52% 53%
Diesel fuels 39% 39% 38%
Fuel oil 3% 3% 2%
Asphalt 4% 3% 4%
LPG and other 3% 3% 3%
Total 100% 100% 100%
Table of Content

Crude Oil and Feedstock Supplies
The Navajo Refinery is situated near the Permian Basin, an area that has historically, and continues to have, abundant supplies of crude oil available both for regional users and for export to other areas. We purchase crude oil from independent producers in southeastern New Mexico and west Texas as well as from major oil companies. The crude oil is gathered through HEP's pipelines and through third-party tank trucks and crude oil pipeline systems for delivery to the Navajo Refinery.


We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in Texas and the Mid-Continent area that are delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP's intermediate pipelines running from Lovington to Artesia. From time to time, we purchase gas oil, naphtha and light cycle oil from other refiners for use as feedstock.



Rocky Mountain Region (Cheyenne and Woods Cross Refineries)

Facilities
The Cheyenne and the Woods Cross Refineries have crude oil processing capacities of 52,000 and 45,000 barrels per stream day, respectively. The Cheyenne Refinery processes heavy Canadian crudes as well as local sweet crudes such as that produced from the Bakken shale and similar resources. The Woods Cross Refinery processes regional sweet and black wax crude as well as Canadian sour crude oils into high-value light products.

Table of Content

The following table sets forth information about our Rocky Mountain region operations, including non-GAAP performance measures.
  Years Ended December 31,
  2017 2016 2015
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)      
Crude charge (BPD) (1)
 77,380
 63,650
 68,770
Refinery throughput (BPD) (2)
 84,790
 68,870
 74,480
Sales of produced refined products (BPD) (3)
 79,840
 66,950
 68,570
Refinery utilization (4)
 79.8% 65.6% 82.9%
       
Average per produced barrel sold (5)
      
Refinery gross margin (6)
 $15.78
 $8.80
 $18.43
Refinery operating expenses (7)
 10.46
 10.17
 9.90
Net operating margin $5.32
 $(1.37) $8.53
       
Refinery operating expenses per throughput barrel (8)
 $9.85
 $9.89
 $9.12

  Years Ended December 31,
  2017 2016 2015
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)      
Feedstocks:      
Sweet crude oil 34% 39% 42%
Heavy sour crude oil 35% 35% 37%
Black wax crude oil 22% 18% 13%
Other feedstocks and blends 9% 8% 8%
Total 100% 100% 100%

Footnote references are provided under our Consolidated Refinery Operating Data table on page 7.

The Cheyenne Refinery facility is located on a 255-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, coking, FCC, HF alkylation, catalytic reforming, hydrodesulfurization of naphtha and distillates, butane isomerization, hydrogen production, sulfur recovery and product blending units. The operating units at the Cheyenne Refinery include both newly constructed units and older units that have been upgraded over the years.

The Woods Cross Refinery facility is located on a 200-acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since before 1950. The facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 45,000 BPSD capacity.

We own and operate 4 miles of hydrogen pipeline that connects the Woods Cross Refinery to a hydrogen plant located on the property of Chevron's Salt Lake City Refinery. Additionally, HEP owns and operates 12 miles of crude oil and refined products pipelines that allows us to connect our Woods Cross Refinery to common carrier pipeline systems.

Markets and Competition
The Cheyenne Refinery primarily markets its products in eastern Colorado, including metropolitan Denver, eastern Wyoming and western Nebraska. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel directly from the truck rack at the refinery, therefore, eliminating transportation costs. The Cheyenne Refinery ships refined products via the Magellan pipeline serving Denver and Colorado Springs, Colorado.

Denver Market
The most competitive market for the Cheyenne Refinery is the Denver metropolitan area. Three other refineries supply the Denver market: Wyoming refineries near Rawlins and in Casper owned by Sinclair and a refinery in Denver owned by Suncor. Five product pipelines also supply Denver, including three from outside the region.
Table of Content


Utah Market
The Woods Cross Refinery's primary market is Utah, which is currently supplied by a number of local refiners and the Pioneer Pipeline. In addition to our Woods Cross Refinery, local area refiners include Chevron, Andeavor, Big West and Silver Eagle. Other refiners that ship into the Woods Cross market via the Pioneer Pipeline include Sinclair, ExxonMobil, CHS and Phillips 66. We estimate the four local refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately 165,000 BPD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and Phillips 66. Approximately 40% - 45% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under a long-term supply agreement.

Idaho, Wyoming, Eastern Washington and Nevada Markets
We supply a small percentage of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery ships refined products over a common carrier pipeline system owned by Andeavor Logistics Northwest Pipelines LLC (“Andeavor Logistics”) to numerous terminals, including HEP's terminal at Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Andeavor Logistics. We sell to branded and unbranded customers in these markets. In 2012, we began shipping refined products to Cedar City, Utah and Las Vegas, Nevada via the UNEV Pipeline. The majority of the Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan's CalNev common carrier pipeline system.

Products
Set forth below is information regarding refined product sales attributable to our Rocky Mountain region:
  Years Ended December 31,
  2017 2016 2015
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)      
Sales of refined products:      
Gasolines 58% 59% 57%
Diesel fuels 32% 32% 35%
Fuel oil 3% 2% 3%
Asphalt 4% 4% 3%
LPG and other 3% 3% 2%
Total 100% 100% 100%

Crude Oil and Feedstock Supplies
Crude oil is transported to the Cheyenne Refinery from suppliers in Canada, Colorado, Nebraska, North Dakota and Montana via common carrier pipelines owned by Spectra, Plains, HEP and Suncor Energy, as well as by truck. The Woods Cross Refinery currently obtains crude oil from suppliers in Canada, Wyoming Utah and ColoradoUtah as delivered via common carrier pipelines, including the SLC Pipeline and Frontier Pipeline owned by HEP. Supplies of black wax crude oil are shipped via truck.




HollyFrontier Asphalt Company


We manufacture commodity and modified asphalt products at our manufacturing facilities located in Glendale, Arizona; Albuquerque, New Mexico; Artesia, New Mexico and Catoosa, Oklahoma. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity and modified asphalt emulsions from base asphalt materials provided by our refineries and third-party suppliers. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our refineries and third-party suppliers. Our Catoosa facility manufactures specialty modified asphalt and commodity asphalt products. We market these asphalt products in Arizona, California, Colorado, New Mexico, Oklahoma, Kansas, Missouri, Texas, Arkansas and northern Mexico. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.




LUBRICANTS AND SPECIALTY PRODUCTS OPERATIONS


Our lubricants and specialty products operations consist of our Petro-Canada Lubricants, Red Giant Oil, Sonneborn and the Tulsa rack forward businesses.

Table of Content


Our Petro-Canada Lubricants business produces automotive, industrial and food grade lubricants and greases, base and process oils and specialty fluids andfluids. It is one of the largest manufacturermanufacturers of high margin Group III base oils in North America and is the world's largest producer of pharmaceutical white oils.America. Products are marketed in over 80 countries worldwide to a diverse customer base through a global sales force and distributor network.


Our Red Giant Oil business provides high quality lubricants to the railroad industry, which represents a market of a small number of high-value customers who associate the Red Giant Oil name with a niche suite of products.

Sonneborn is a producer of specialty hydrocarbon chemicals such as white oils, petrolatums and waxes for the personal care, cosmetic, pharmaceutical and food processing industries. Combined with Petro-Canada Lubricants, it is one of the world's largest producers of pharmaceutical white oils.

Our Tulsa Refinery produces high quality base oils, process oils, waxes, horticultural oils and asphalt performance products. Products are marketed worldwide through strategically located terminals in the United States and selected distributors internationally.


The following table sets forth information about our lubricants and specialty products operations and includes our Petro-Canada Lubricants businessRed Giant Oil for the period FebruaryAugust 1, 20172018 (date of acquisition) through December 31, 2017.2020, and Sonneborn for the period February 1, 2019 (date of acquisition) through December 31, 2020.
13
Table of Content
Years Ended December 31,
 Years Ended December 31,202020192018
Lubricants and Specialty Products 2017 2016 2015Lubricants and Specialty Products
Throughput (BPD) 21,710
 —
 —
Throughput (BPD)19,645 20,251 19,590 
Sales of produced refined products (BPD) 31,480
 12,030
 11,140
Sales of produced refined products (BPD)32,902 34,827 30,510 
      
Sales of produced refined products:      Sales of produced refined products:
Finished products 45% 50% 52%Finished products49 %49 %48 %
Base oils 31% 50% 48%Base oils26 %27 %31 %
Other 24% —% —%Other25 %24 %21 %
Total 100% 100% 100%Total100 %100 %100 %


PCLI owns and operates a refineryproduction facility located in Mississauga, Ontario having lubricant production capacity of 15,600 barrels per stream dayBPD and has the flexibility to match unique lubricant product formulations. The primary operating units includeare high-pressure hydrotreating and hydrofinishing, solvent dewaxing and catalytic dewaxing. In addition, the facility operates a hydrogen plant, naphtha hydrotreater and hydrotreating, solvent dewaxing, hydrodentrification, catalytic dewaxing and hydrobon/platformer units.reformer, along with other utility units to support production. The Mississauga plant also includes packaging facilities and has extensive distribution capabilities with marine, truck and rail access.



Red Giant Oil, headquartered in Council Bluffs, Iowa, owns and operates blending and distribution facilities in Council Bluffs, Iowa; Joshua, TX and Newcastle, Wyoming.

Sonneborn has manufacturing facilities in Petrolia, Pennsylvania and the Netherlands. The Sonneborn Petrolia site has a production capacity of 6,000 BPD with flexibility to produce a full range of finished specialty products. The primary operating unit is a high-pressure hydrotreater with hydrofinishing. In addition, the facility operates a hydrogen plant along with other utility units to support production. The Petrolia plant also includes packaging facilities with distribution capabilities through rail and trucking. The Sonneborn Netherlands sites include processing facilities in Amsterdam and Koog with a production capacity of approximately 1,500 BPD. The primary operating units include base oil acid treating, percolation filtration, and bleaching & steaming operations. The Netherlands sites include packaging facilities with distribution capabilities through truck and marine.


HOLLY ENERGY PARTNERS, L.P.


HEP is a Delaware limited partnership that trades on the New York Stock Exchange under the trading symbol “HEP.” HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and refinery processing units that principally support our refining and marketing operations, as well as other third-party refineries, in the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States and Delek's refinery in Big Spring, Texas.States. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), the owner of a pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”) and associated product terminals;terminals, and a 50% ownership interest in each of Osage Pipe Line Company, LLC, the owner of a pipeline running from Cushing, Oklahoma to El Dorado, Kansas (the “Osage Pipeline”); and a 50% interest in, Cheyenne Pipeline, LLC, the owner of a pipeline running from Fort Laramie, Wyoming to Cheyenne, Wyoming (the “Cheyenne Pipeline”). and Cushing Connect Pipeline & Terminal LLC (“Cushing Connect”), the owner of a crude oil storage terminal in Cushing, Oklahoma and a pipeline under construction that will run from Cushing, Oklahoma to our Tulsa Refineries.


HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Delek, by charging fees for terminalling and storing refined products and other hydrocarbons and providing other services at its storage tanks, terminals and refinery processing units. HEP does not take ownership of products that it transports, terminals, stores or refines; therefore, it is not directly exposed to changes in commodity prices.


HEP's recent acquisitions (2015 through present) are summarized below:
14
Table of Content

Investment in Joint Venture
SLC Pipeline
Cushing Connect Joint Venture
In October 2019, HEP Cushing LLC, a wholly-owned subsidiary of HEP, and Frontier Aspen
On October 31, 2017, HEP acquired the remaining 75% interest in SLC Pipeline LLC, the owner ofPlains Marketing, L.P., a pipeline that serves refineries in the Salt Lake City, Utah area (the “SLC Pipeline”), and the remaining 50% interest in Frontier Aspen LLC, the owner of a pipeline running from Wyoming to Frontier Station, Utah (the “Frontier Pipeline”), from subsidiarieswholly-owned subsidiary of Plains All American Pipeline, L.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect, for total cash consideration(i) the development, construction, ownership and operation of $250.0 million.
Tablea 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 our Tulsa Refineries and (ii) the ownership and operation of Content


Woods Cross Assets
On October 3, 2016, HEP acquired from us all1.5 million barrels of crude oil storage in Cushing, Oklahoma (the “Cushing Connect Terminal”). The Cushing Connect Terminal was fully in service beginning in April 2020, and the membership interests of Woods Cross Operating LLC, which owns the crude unit, FCCU and polymerization unit of the first phase of our Woods Cross Refinery expansion project that was completedCushing Connect Pipeline is expected to be placed in service during the second quarter of 2016, for cash consideration of approximately $278.0 million.2021. Long-term commercial agreements have been entered into to support the Cushing Connect assets.


Cheyenne Pipeline
On June 3, 2016, HEP 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. The 87-mile crude oil pipeline runs from Fort Laramie, Wyoming to Cheyenne, Wyoming and has an 80,000 BPD capacity.

Tulsa Tanks
On March 31, 2016, HEP acquired crude oil tanks located at our Tulsa Refineries from Plains for $39.5 million.

Magellan Asset Exchange
On February 22, 2016, we obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in exchange for a 20-year terminalling services agreement, whereby, a subsidiary of Magellan Midstream Partners (“Magellan Midstream”)Cushing Connect will provide terminalling services for all of our 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 our 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 our El Dorado Refinerycontract with crude oil. Also on February 22, 2016, we contributed the 50% membership interest in Osage to HEP, and in exchange received HEP's El Paso terminal. Pursuant to this exchange, HEP agreed to build two connections to Magellan Midstream's El Paso terminal. In addition, HEP agreed to become operator of the Osage Pipeline.
El Dorado Asset Transaction
On November 1, 2015, HEP acquired from us newly constructed naphtha fractionation and hydrogen generation units at our El Dorado Refinery for cash consideration of $62.0 million.

Frontier Pipeline Transaction
On August 31, 2015, HEP purchased a 50% interest in Frontier Aspen LLC (previously known as Frontier Pipeline Company), owner of the Frontier Pipeline, from an affiliate of Enbridge, Inc. for $55.0HEP 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 Terminal. The total investment in Cushing Connect will be shared proportionately among the partners, and HEP estimates its share of the cost of the Cushing Connect Terminal contributed by Plains and Cushing Connect Pipeline construction costs are approximately $65.0 million. The 289-mile crude oil pipeline runs from Casper, Wyoming to Frontier Station, Utah, has a 72,000 BPD capacity and supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection toHowever, any Cushing Connect Pipeline construction costs exceeding 10% of the SLC Pipeline. As noted above, HEP acquired the remaining 50% interest on October 31, 2017.budget are borne solely by HEP.

Crude Tank Farm Asset Transaction
On March 6, 2015, HEP purchased an existing crude tank farm adjacent to our El Dorado Refinery from an unrelated third-party for $27.5 million in cash. We are the main customer of this crude tank farm.



Transportation Agreements


Agreements with HEP
HEP serves our refineries under long-term pipeline, terminal and tankage throughput agreements and refinery processing tolling agreements expiring from 2020 2021 through 2036. UnderUnder these agreements, we pay HEP fees to transport, store and process throughput volumes of refined products, crude oil and feedstocks on HEP's pipelines, terminals, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to HEP, including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2017,2020, these agreements result inrequired minimum annualized payments to HEP of $351.1 million. However, as previously disclosed, subsequent to year end these agreements were modified to account for the conversion of our Cheyenne Refinery to renewable diesel production, and as of January 1, 2021, require minimum annualized payments to HEP of $324.5$341.9 million.


Our transactions with HEP including the transactions discussed above and fees paid under our transportation agreements with HEP and UNEV are eliminated and have no impact on our consolidated financial statements.


Table of Content

Agreement with Delek
HEP has a 15-year pipelines and terminals agreement with Delek expiring in 2020, under which Delek has agreed to transport on HEP's pipelines and throughput through its terminals, volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but will not decrease below the initial tariff rate. Also, HEP has a capacity lease agreement with Delek under which Delek leases space on HEP's Orla to El Paso pipeline for the shipment of up to 15,000 barrels of refined product per day. The terms under this agreement expire in 2018 through 2022.

As of December 31, 2017,2020, HEP's assets included:


Pipelines
•approximately 810800 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico;
•approximately 510 miles of refined product pipelines that transport refined products from Delek's Big Spring refinery in Texas to its customers in Texas and Oklahoma;
•two 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico;
•one 65-mile intermediate pipeline that is used for the shipment of crude oil from the gathering systems in Barnsdall and Beeson, New Mexico to our Navajo Refinery;
•the SLC Pipeline, a 95-mile intrastate crude oil pipeline system that transports crude oil into the Salt Lake City, Utah area from the Utah terminus of the Frontier Pipeline, as well as crude oil flowing from Wyoming and Utah via Plains Rocky Mountain Pipeline;
•the Frontier Pipeline, a 289-mile crude oil pipeline running from Casper, Wyoming to Frontier Station, Utah through a connection to the SLC Pipeline;
•approximately 940 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that primarily deliver crude oil to our Navajo Refinery;
•approximately 8 miles of refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah;
•gasoline and diesel connecting pipelines that support our Tulsa East facility;
•five intermediate product and gas pipelines between our Tulsa East and Tulsa West facilities;
15
Table of Content
•crude receiving assets located at our Cheyenne Refinery;facility;
•a 75% interest in the UNEV Pipeline, a 427-mile, 12-inch refined products pipeline running from Woods Cross, Utah to Las Vegas, Nevada;
•a 50% interest in the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to our El Dorado Refinery and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas; and
•a 50% interest in the Cheyenne Pipeline, an 87-mile crude oil pipeline running from Fort Laramie, Wyoming to Cheyenne, Wyoming.Wyoming; and

•a 50% interest in Cushing Connect, a joint venture formed to construct a 160,000 BPD pipeline to connect the Cushing, Oklahoma crude oil hub to our Tulsa Refineries.

Refined Product Terminals and Refinery Tankage
•three refined product terminals located in Orla, Texas and Moriarty and Bloomfield, New Mexico; and Tucson, Arizona,Mexico, with an aggregate capacity of approximately 600,000458,000 barrels, that are integrated with HEP's refined product pipeline system that serves our Navajo Refinery;
•one refined product terminal located in Spokane, Washington, with a capacity of approximately 400,000420,000 barrels, that serves third-party common carrier pipelines;
•one refined product terminal near Mountain Home, Idaho, with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;
•two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of approximately 500,000600,000 barrels, that are integrated with HEP's refined product pipelines that serve Delek's Big Spring, Texas refinery;
•a refined product terminal in Catoosa, Oklahoma that stores specialty lubricant products and is utilized by our Tulsa Refineries;
•a refined product loading rack facility at each of our El Dorado, Tulsa, Navajo Cheyenne and Woods Cross Refineries and our Cheyenne facility, heavy product / asphalt loading rack facilities at our Tulsa East facility, Navajo Refinery Lovington facility and Cheyenne Refinery,facility, LPG loading rack facilities at our El Dorado Refinery, Tulsa West facility and Cheyenne Refinery,facility, lube oil loading racks at our Tulsa West facility and crude oil Leased Automatic Custody Transfer units located at our Cheyenne Refinery;facility;
•on-site crude oil tankage at our Tulsa, El Dorado, Navajo Cheyenne and Woods Cross Refineries and Cheyenne facility having an aggregate storage capacity of approximately 1,350,0001,530,000 barrels;
Table of Content

•on-site refined and intermediate product tankage at our El Dorado and Tulsa and Refineries and Cheyenne Refineriesfacility having an aggregate storage capacity of approximately 8,800,0008,600,000 barrels;
•eleven crude oil tanks adjacent to our El Dorado Refinery with a capacity of approximately 1,200,0001,100,000 barrels that primarily serve our El Dorado Refinery;
•crude oil tankage with an aggregate storage capacity of approximately 480,000 barrels that primarily serve our Navajo Refinery;
•Frontier Pipeline's tankage with an aggregate capacity of approximately 72,000380,000 barrels; and
•a 75% interest in UNEV Pipeline's product terminals near Cedar City, Utah and Las Vegas, Nevada with an aggregate capacity of approximately 615,000 barrels.660,000 barrels; and

•a 50% interest in Cushing Connect's crude oil tankage with a capacity of approximately 1,500,000 barrels in Cushing, Oklahoma.

Refinery Processing Units
•a naphtha fractionation tower at our El Dorado Refinery, with a capacity of 50,000 BPD of desulfurized naphtha;
•a hydrogen generation unit at our El Dorado Refinery, with a capacity of 6.1 million standard cubic feet per day of natural gas.
•a crude unit, which is primarily an atmospheric distillation tower, a desalter and heat exchangers, at our Woods Cross Refinery, with a feedstock capacity of 15,000 BPD of crude oil;
•a FCC unit at our Woods Cross Refinery, which converts crude oil to high-value refined products such as gasoline, diesel and liquefied petroleum gases, with a capacity of 8,000 BPD; and
•a polymerization unit at our Woods Cross Refinery, that uses the output of the fluid cracking unit and converts them into gasoline blendstock, with a capacity of 2,500 BPD.

16

Table of Content
ADDITIONAL OPERATIONS AND OTHER INFORMATION


Corporate Offices
We lease approximately 92,000 square feet for ourOur principal corporate offices are leased and located in Dallas, Texas. The lease for our principal corporate offices expires in 2023. Functions performed in theour Dallas office include overall corporate management, refinery and HEP management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.


EmployeesHuman Capital
Our People
Our people differentiate us from our peers. Our “One HFC Culture” focuses on four key values – safety, integrity, teamwork and Labor Relationsownership. These values influence our decisions, shape our behaviors and provide the opportunity for our employees to thrive. Safety is our first priority. We care about our people and have implemented policies and procedures designed to help make sure they 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.

As of December 31, 2017,2020, we had 3,5223,891 employees located in the following geographies: 2,933 employees in the United States, 711 employees in Canada and 247 employees in Europe and Asia. As of which 1,139 are currentlyDecember 31, 2020, 1,306 employees were covered by collective bargaining agreements havingwith various expiration dates ranging between 20182021 and 2020.2024. We considerhave experienced no material interruptions of operations due to disputes with our employees and management attempts to have and believes that we have positive working relationships with our local unions and their members.

Oversight
Our Board of Directors and Board committees provide oversight on our strategies and policies related to human capital management. Our Compensation Committee is responsible for periodically reviewing HollyFrontier’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 our executive succession planning. Our Nominating, Governance and Social Responsibility Committee oversees our policies and practices regarding human rights in our operations and supply chain. This high level oversight is designed to ensure that our actions are well aligned with our strategies in attracting, retaining and developing a workforce that aligns with our values and strategies.

Diversity & Inclusion
Our 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. Increasing our diversity and inclusion efforts is an organizational priority and strategic oversight of our efforts is provided by our Compensation Committee. We have introduced diversity awareness programs focused on increasing the number of underrepresented persons in engineering roles in our refineries and corporate office. Our 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, we have two employee resource groups focused on strengthening our support of women and veterans in the workplace.

Health & Safety
The safety of our employees, contractors and communities is an overarching priority and fundamental to our operational success. We are grounded by our “Goal Zero” vision, which reflects our belief that safe production can be achieved each and every day. Our commitment to safety is embedded throughout our organization, from frontline employees and contractors to our executive leadership and board of directors. Our Operational Excellence Management System provides the framework through which we identify, monitor and reduce risks. Our Environment, Health and Safety (“EHS”) Leadership Council, comprised of company executives, including our CEO, business unit leaders and corporate safety specialists, sets EHS strategy and reviews performance. The Environmental, Health, Safety and Public Policy Committee of our Board of Directors provides board-level oversight of our strategies and performance in these areas.

To achieve Goal Zero, our employee relationsand contractor safety education and training programs are conducted on an ongoing basis. We set specific goals for workplace safety and measure attainment of those goals. Over the past five years ended December 31, 2020, our OSHA total recordable incident rate (“TRIR”) declined by 35 percent. In response to be good.the coronavirus (“COVID-19”) pandemic, and with the health and safety of our employees as a top priority, we have temporarily modified our business practices by limiting employee and contractor presence at our facilities to essential operating personnel, using a work from home policy, restricting travel, and quarantining employees when necessary.

17
Table of Content
Environmental
Total Rewards & Development
We believe that the health of our company is linked to the performance and health of our people. We want to inspire and empower our employees to feel confident in their long-term well-being and are committed to offering a comprehensive and competitive total rewards programs for our employees, as benchmarked against our peers. While our benefit offerings vary depending on each country’s market practices, they are designed to support employee health, financial and emotional needs. Our benefits include comprehensive coverage for health care, a competitive retirement savings benefit, vacation and holiday time and other income protection and work life benefits. We also provide tools to help recognize and reward employee performance consistent with our One HFC Culture.

Consistent with our culture of ownership and growth, we offer training, development and engagement programs across every level of our organization to provide employees the opportunity to develop their career by enhancing skills and capabilities consistent with the needs of the business. In 2019, we launched HFC LEAD. “LEAD” stands for Leadership, Excellence and Development and is comprised of a number of programs focused on developing current and future leaders, including the Future HFC Leader Development, Front Line Leader, and Leading the HFC Way programs. We invested $6.0 million in our employee training and development programs in fiscal 2020.

Governmental Regulation
We are subject to numerous international, federal, state, provincial and local laws and regulations regulating worker health and safety, the discharge of substances into the environment, or otherwise relating to the protection of the environment and natural resources. Permits or other authorizations are required under these laws and regulations for the operation of our refineries, pipelines and related facilities, which can result in the imposition of costly reporting, installation of pollution control equipment and maintenance obligations. Moreover, these permits and authorizations are subject to revocation, modification and renewal, as well as challenges from third parties.


Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects; and the issuance of injunctive relief limiting or prohibiting certain operations.operations; and reputational harm. In addition, many environmental laws provide a mechanism for citizens to file suit against regulated facilities for alleged environmental violations. Compliance with applicable environmental laws, regulations and permits or other authorizations will continue to have an impact on our operations, the results of our operations and our capital expenditures.


Rate Regulation - Some of HEP’s existing pipelines are considered interstate common carrier pipelines subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (the “ICA”). The ICA 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 ICA permits interested persons to challenge newly proposed or changed rates and authorizes FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

The Energy Policy Act of 1992 deemed petroleum products pipeline tariff rates that were (i) in effect for the 365-day period ending on the date of enactment or (ii) in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period, in each case, to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. 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.

18
Table of Content
Clean Air Act - Our operations are subject to certain requirements of the Federal Clean Air Act (“CAA”) as well as related state and local laws and regulations. Certain CAA regulatory programs applicable to our refineriesfacilities require capital expenditures for the installation of certain air pollution control devices, operational procedures to minimize emissions, and monitoring and reporting of emissions. Additionally, the Environmental Protection Agency (“EPA”) has the authority under the CAA to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. Also, in October 2015, the EPA lowered thehas reduced several National Ambient Air Quality StandardStandards (“NAAQS”) for ozone from 75 to 70 parts per billion,, and state implementation of thesuch revised NAAQS could result in stricter permitting requirements, delay or the inability to obtain such permits, and increased expenditures for pollution control equipment, the costs of which could be significant. Moreover, in February 2016, a new EPA rule became effective that requires, among other things, benzene monitoring at the refinery fence line beginning in January 2018 and submittal of fence line monitoring data to the EPA on a quarterly basis; upgraded storage tank controls requirements, including new applicability thresholds; enhanced performance requirements for flares, continuous monitoring of flares and pressure release devices, and analysis and remedy of flare release events; compliance with emissions standards for delayed coking units; and requirements related to air emissions resulting from startup, shutdown and maintenance
Table of Content

events. These new rules, as well as subsequent rulemaking under the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years and result in increased costs on our operations.


Fuel Quality Regulation - Also, weWe are subject to the EPA’s Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”(also known as the Mobile Source Air Toxics rule, or “MSAT2”) regulations that impose reductions in the benzene content of our produced gasoline. OurIn addition to reducing benzene concentration in our gasoline, our refineries currently purchase benzene credits to meet these requirements. If economically justified or otherwise determined to be beneficial, we couldmay implement additional benzene reduction projects to eliminate or reduce the need to purchase benzene credits.


Pursuant to the Energy Independence and Security Act of 2007 (“EISA”), and the EPA’s corresponding Renewable Fuel Standard (“RFS”) regulations, most refiners are required to blend increasing amounts of biofuels with refined products through 2022 or purchase Renewable Identification Numbers (“RINs”) in lieu of blending. Under the RFS, the percentage of renewable fuels that refineries are obligated to blend into their finished petroleum products is adjusted annually. In November 2017,2018, the EPA finalized the RFS targets for 2018,2019, which maintained the volume required for conventional (i.e., corn ethanol) renewable fuel, increased the volume required for advanced biofuels, and reducedincreased the volume required for cellulosic biofuel compared to the 20172018 RFS requirements. The EPA also maintainedincreased the biomass-based diesel volume for 20192020 compared to 2018.2019. The EPA has not yet finalized the 2021 RFS requirements for any fuel other than biodiesel, creating some uncertainty regarding our compliance obligations for 2021. Because the EISA requires specified volumes of biofuels, if the demand for motor fuels decreases in future years, even higher percentages of biofuels may be required.


The EPA has historically used its waiver authority to establish volumes lower than the statutory volumes required by EISA, but the EPA’s interpretation of its waiver authority, as well as its implementation of the RFS, has been subject to numerous court challenges. Additional lawsuitsLawsuits have been filed by refiners attemptingthe renewable fuel industry challenging the EPA's grant of small refinery exemptions. For additional information regarding risks relating to moveour small refinery exemptions, see Item 1A, “Risk Factors - The availability and cost of renewable identification numbers and other required credits could have an adverse effect on our financial condition and results of operations.” Legal challenges of the point of compliance for the RFS from refiners to importers and blenders of fuels.EPA's decision are ongoing. We cannot predict the outcome of these matters or whether they may result in increased RFS compliance costs. There also continues to be a shortage of advanced biofuel production resulting in increased difficulties meeting RFS mandates. As a result, we may be unable to blend sufficient quantities of ethanol and biodieselrenewable fuel to meet our requirements and, therefore, may have to purchase an increasing number of RINs. It is not possible at this time to predict with certainty what those volumes or costs may be, but given the potential increase in volumes and the volatile price of RINs, increases in renewable volume requirements could have an adverse impact on our results of operations.


Finally, while there is no current regulatory standard that authenticates RINs that may be purchased on the open market from third parties, we believe that the RINs we purchase are from reputable sources, are valid and serve to demonstrate compliance with applicable RFS requirements. However, if any of the RINs purchased by us on the open market are subsequently found by the EPA to be invalid, we could secureincur significant costs, penalties, or other liabilities in connection with replacing any invalid RINs and resolving any enforcement action brought by the EPA.


In April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which requires a reduction in annual average gasoline sulfur content from 30 ppm to 10 ppm. These new requirements, other CAA requirements, and other presently existing or future environmental regulations may cause us to make substantial capital expenditures and purchase sulfur credits at significant cost to enable our refineries to produce products that meet applicable requirements.


19
Table of Content
Climate Change - In recent years, various legislative and regulatory measures to address climate change and greenhouse gas (“GHG”) emissions (including carbon dioxide, methane and nitrous oxides) have been discussed or implemented. They include proposed and enacted federal regulation and state actions to develop statewide, regional or nationwide programs designed to control and reduce GHG emissions from fixed sources, such as our refineries, as well as power plants, mobile transportation sources and fuels. Measures to date have included but are not limited to cap and trade programs, carbon taxes, vehicle efficiency standards, electric vehicle mandates, combustion engine phaseouts and low carbon fuel standards. Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws or regulations that may be adopted to restrict or reduce GHG emissions will likely require us to incur increased operating and capital costs. In August 2015, the EPA finalized the “Clean Power Plan” requiring states to reduce carbon dioxide emissions from coal firedcoal-fired power plants that will likely result in a combination of plant closures, switching to renewable energy and natural gas, and demand reduction. However, the Clean Power Plan is currently being litigated in various courts, and the U.S. Supreme Court has stayed implementation of the rule pending the outcome of those judicial challenges. In October 2017,July 2019, the EPA proposed to repealissued a replacement rule titled the Affordable Clean Energy (“ACE”) Rule, which replaced the Clean Power Plan and is focused solely on December 18, 2017,electric generating units. However, in January 2021, the EPA issuedD.C. Circuit vacated the ACE rule, and the Biden Administration may consider reimplementing the Clean Power Plan or a notice seeking comments on whether to promulgate a replacementsimilar rule. If upheld, this ruleNeither the Clean Power Plan nor the Affordable Clean Energy Rule would not directly affect our operations, but, tooperations. To the extent it orthe EPA fully implements a similar rule is fully implemented,that imposes higher costs on electricity generating units it could result in increased power costs for our refineries in future years.

Table of Content


EPA rules require us to report GHG emissions from our refinery operations and consumer use of fuel products produced at our refineries on an annual basis. While the cost of compliance with the reporting rule is not material, data gathered under the rule may be used in the future to support additional regulation of GHG. Moreover, the EPA directly regulates GHG emissions from refineries and other major sources through the Prevention of Significant Deterioration (“PSD”) and Federal Operating Permit programs and may require Best Available Control Technology (“BACT”) for GHG emissions above a certain threshold if emissions of other pollutants would otherwise require PSD permitting. While this does not impose any limits or controls on GHG emissions from current operations, future projects or operational changes that increase GHG emissions, such as capacity increases, may be subject to emission limits or technological requirements pertaining to GHG emissions, such as BACT.


Severe limitations on GHG emissions could also adversely affect demand for the gasoline that we produce. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production activities and result in decreased production of oil, which indirectly could have an adverse impact on our operations. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other extreme weather events; if any such effects were to occur, they could have an adverse effect on our operations.


The incoming administration is proposing an “all of government” approach to climate change in which the federal government would use not only its regulatory and enforcement authority but also its policy and purchasing power to encourage investment and use of renewable energy sources and to otherwise impede and reduce fossil fuel use. This approach may include elements that could directly or indirectly result in decreased demand for transportation fuel and could have an adverse impact on our operations. For example, on January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across governmental agencies and economic sectors.

Water Discharges - Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in conformance with legal authorization, such as pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. The EPA commenced a study from 2015-2017 related to the discharges of metals and dioxin from petroleum refining operations and wastewater discharges from refineries in connection with the consideration of new effluent limitation guidelines that would be incorporated into refinery sector NPDES permits. To date, the EPA has not proposed any new effluent limitation guidelines applicable to our operations, but future rulemakings related to this issue could require us to incur increased costs related to the treatment of wastewater resulting from our operations.


20
Table of Content
The CWA also regulates filling or discharges to wetlands and other “Waters“waters of the U.S.United States.” In 2015,On January 23, 2020, the EPA, in conjunction with the U.S. Army Corps of Engineers (the “Corps”), issued a final rule regarding the definition of “Waters“waters of the U.S.,United States,” which expandednarrowed the regulatory reach of the existing CWA regulations.regulations relative to a prior 2015 rulemaking. The final rule is currently stayed pending litigation in various courts, and the EPA has expressed its intent to repeal and potentially replace the rule. Ifbecame effective June 22, 2020. Because the rule or any replacement rule expandsdoes not expand the scope of the CWA’s jurisdiction, we could face increased costsit will not likely adversely impact our operations; however, the final rule is subject to litigation, and delays with respectmultiple challenges to obtaining permits for discharges resulting from our operations.the EPA's prior rulemakings remains pending, both of which create uncertainty. Additionally, the new administration may seek to revise or withdraw the final rule, creating further uncertainty.


Hazardous Substances and Wastes - We generate wastes that may be subject to the Resource Conservation and Recovery Act and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Although the EPA is currently working on several rulemakings that could impact how our refineries manage various waste streams, it does not appear that these rules will significantly impact our refineries.


The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes strict, and under certain circumstances, joint and several liability on certain classes of persons who are considered to be responsible for the cost of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. These persons include current and former owners or operators of property where a release has occurred, and any persons who disposed of, or arranged for the transport or disposal of, hazardous substances at the property. In the course of our historical operations, as well as in our current operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may be subject to cleanup and cost recovery actions under CERCLA in the future. Similarly, locations now owned or operated by us, where third parties have disposed such hazardous substances in the past, may also be subject to cleanup and cost recovery actions under CERCLA. Some states have enacted laws similar to CERCLA which impose similar responsibilities and liabilities on responsible parties. It is also not uncommon for neighboring landowners and other third parties to file claims under state law for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.


Table of Content

Oil Pollution Act - The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder generally subject owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the U.S. The OPA also imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.


Other Environmental Regulations - Our Canadian assets and operations are also required to comply with various Canadian federal, provincial and municipal regulations. The regulations are in many cases conceptually similar to those described above for our U.S. operations. The principal legislation affecting our Canadian operations is the Canadian Environmental Protection Act, the Fisheries Act, the Greenhouse Gas Pollution Pricing Act and itstheir regulations at a federal level and various provincial statutes and regulations such as the Ontario Environmental Protection Act, the Ontario Occupational Health and Safety Act and the Ontario Water Resources Act. All these laws contain broad prohibitions against causing harm to air, land, water, people or any other living organism and in many cases contain detailed prescriptive rules governing many aspects of our operations. Regulatory trends towards more stringent emission requirements and operating controls are expected to continue at federal, provincial and local levels.


21
Table of Content
Additionally, our assets and operations in the Netherlands are required to comply with Dutch regulations that are similar to, and in some cases more stringent than, those described above for our U.S. operations. The statutes to which our Dutch assets and operations are subject include the Environmental Protection Act, the Activities Decree, the Environmental Licensing (General Provisions) Act, the Water Act, the Soil Protection Act, the Major Accidents (Risks) Decree, the European Birds and Habitats Directive, the Economic Offences Act and other subordinate decrees and regulations relative to environmental control, permitting and enforcement. However, a large legislative operation is being developed that should lead to the integration of all environmental laws in one, being the Environment and Planning Act, which is expected to enter into force in January 2022. Generally, these regulations create a system of environmental permits covering the most significant emissions to water, air and soil, as well as other environmental impacts. The Netherlands also participates in certain broader European legal initiatives, including GHG cap and trade programs. Additionally, in December 2019, the High Council of the Netherlands upheld a court order for the government of the Netherlands to reduce the country's GHG emissions by 25% (compared to 1990) by 2020, and in January 2020,the Climate Act came into force, with the goal of significantly reducing GHG emissions by 49% (compared to 1990) by 2030 and by at least 95% (compared to 1990) by 2050. Furthermore, the target is that 100% of the electricity production will be CO2 neutral in 2050. The Climate Act also establishes that the government must prepare a Climate Plan. The first Climate Plan covers the period between 2021 and 2030 and includes measures in view of a reduction of 49% of GHG emissions in 2030. It is unclear what further measures the Dutch government will take to reduce GHG emissions pursuant to this law.

Enforcement and Litigation Proceedings - As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. These matters include soil and water contamination, air pollution, GHG emissions, personal injury and property damage allegedly caused by substances that we manufactured, handled, used, released or disposed. We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from past releases of refined product and crude oil into the environment. As of December 31, 2017,2020, we had an accrual of $103.7$115.0 million related to such environmental liabilities.


We are and have been the subject of various local, state, provincial, federal and private proceedings and inquiries relating to compliance with environmental laws and regulations and conditions, including those discussed above. Compliance with current and future environmental regulations is expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at pipeline transportation facilities.significant. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued, if applicable.


Occupational Health and Safety - Our operations are subject to various laws and regulations relating to occupational health and safety, including the Occupational Safety and Health Act (“OSHA”) and, comparable state statutes.statutes, Canadian regulations applicable to our operations in Canada and Dutch regulations, including the Health and Safety Act, applicable to our operations in the Netherlands. We maintain a comprehensive safety program, including mechanical integrity and safety-related maintenance programs and training, to ensure compliance with all applicable laws and regulations to protect the safety of our workers and the public. OurSome of our operations are also subject to OSHA Process Safety Management (“PSM”) regulations and EPA Risk Management Plan (“RMP”) regulations, both of which are designed to prevent or minimize the consequences of catastrophicchemical accidents and any resulting releases of toxic, reactive, flammable or explosive chemicals. In January 2017, the EPA revised the RMP requirements for incident investigation and accident history reporting, emergency preparedness, and the performance of process hazard analyses and third party compliance audits. In June 2017, the EPA issued a stay of the revised RMP requirements until 2019, which was immediately challenged by environmental groups, and a final decision remains pending. However, manyMany of the revised requirements do not become effective until 2021.2021, and the EPA issued a final rule in December 2019 that rescinded several of the requirements of the 2017 rule. The new administration may consider reissuing some of the rescinded requirements or making other changes. Also in January 2017, OSHA announced changes to its National Emphasis Program, which specifically identified oil refineries as facilities for increased inspections and instructed inspectors to use data gathered from EPA RMP inspections to identify refiners for additional PSM inspections. Compliance with applicable state and federal occupational health and safety laws and regulations, as well as environmental regulations, has required, and continues to require, substantial expenditures.


Occupational health and environmental legislation, regulations and regulatory programs change frequently. We cannot predict what additional occupational health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing laws or regulations by government agencies could have an adverse effect on our financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.


22
Table of Content
Insurance
Our operations are subject to 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 consisting of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.


Table of Content





Item 1A.Risk Factors

Item 1A.Risk Factors
Risk Factor Summary

Investing in us involves a degree of risk, including the risks described below. Our operating results have been, 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.risk. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the Management’s Discussion & Analysis section and the financial statements and related notes, when decidingprior to investinvesting in our common stock. These risks and uncertainties include, but are not limited to, the following:

Risks Related to our Business:

•The prices of crude oil and refined and finished lubricant products materially affect our profitability, and are dependent upon many factors that are beyond our control.
•To successfully operate our facilities, we are required to expend significant amounts for capital outlays and operating expenditures. If we are unable to complete capital projects at their expected costs or in a timely manner, 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.
•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, as well as certain developments in the global oil markets, have had and may continue to have a material adverse effect on our operations, business, financial condition and results of operations and cash flows.
•Competition in the refining and marketing industry and in our lubricants and specialty products segment is highly competitive, an increase in competition could adversely affect our earnings and profitability.
•A disruption to or proration of the refined product distribution systems or manufacturing facilities we utilize could negatively impact our profitability.
•A material decrease in the supply of crude oil or other raw materials available to our refineries and other facilities could significantly reduce our production levels and negatively affect our operations.
•We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries, and we own a significant equity interest in HEP.
•Our acquisition strategy involves numerous risks, any of which could adversely affect us.
•An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our financial condition and results of operations.
•Potential product, service or other related liability claims and litigation could adversely affect our business, reputation and results of operations.
•We sell many of our lubricants and specialty products through distributors, which presents risks that could adversely affect our operating results.
•Our hedging transactions may limit our gains and expose us to other risks.

Risks Related to Government Regulation

•There are various risks associated with greenhouse gases and climate change, including increased regulation of CO2 emissions, that could result in increased operating costs and litigation and reduced demand for the refined products we produce and investment in our industry.
•The availability and cost of renewable identification numbers and other required credits could have an adverse effect on our financial condition and results of operations.
•We are subject to significant regulation and oversight by governmental agencies. We incur significant costs, and expect to incur additional costs in the future, to comply with existing, new and changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters.
23
Table of Content
•Our business is subject to complex and evolving global laws, regulations and security standards regarding privacy, cybersecurity and data protection, which could result in claims, increased cost of operations, or otherwise harm our business.

General Risk Factors

•Cyberattacks, data security breaches, information technology system failures, network disruptions, terrorist attacks or domestic vandalism, continued global hostilities or other sustained military campaigns could have a material adverse effect on our business, financial condition and results of operations.
•Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions and other disruptive risks for which we may not be adequately insured.
•We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets.. Our credit facility contains certain covenants and restrictions that may constrain our business and financing activities.
•Our business is subject to the risks of international operations, including currency fluctuations.
•We are exposed to the credit risks, and certain other risks, of our key customers and vendors.
•We may be unable to pay future dividends.
•We may be unable to adequately protect our intellectual property, which may increase our cost of doing business or otherwise hurt our ability to compete in the market.
•Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and limit our ability to purchase sufficient quantities of crude oil to operate our refineries at desired capacity.
•Our business may suffer due to a departure of any of our key employees, a shortage of skilled labor or disruptions in our workforce. A portion of our workforce is unionized, and any disruptions in our labor force or adverse employee relations could adversely affect our business.
•The market price of our common stock may fluctuate significantly, and the value of a stockholder’s investment could be impacted.
•Compliance with and changes in tax laws could materially and adversely impact our financial condition, results of operations and cash flows.

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, or results of operations 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.


The availability and cost of renewable identification numbers and other required credits could have an adverse effect on our financial condition and results of operations.RISKS RELATED TO OUR BUSINESS


Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS regulations reflecting the increased volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as RINs, in lieu of such blending. We currently purchase RINs for some fuel categories on the open market in order to comply with the quantity of renewable fuels we are required to blend under the RFS regulations. Recently, due in part to the nation's fuel supply approaching the “blend wall” (the 10% ethanol limit prescribed by most automobile warranties), the price of RINs has been extremely volatile with the price dramatically increasing in recognition of the decrease in RINs availability. While we cannot predict the future prices of RINs, the costs to obtain the necessary number of RINs could be material. If we are unable to pass the costs of compliance with the RFS regulations on to our customers, if sufficient RINs are unavailable for purchase, if we have to pay a significantly higher price for RINs or if we are otherwise unable to meet the RFS mandates, our financial condition and results of operations could be adversely affected.

In addition, the RFS regulations are highly complex and evolving, requiring us to periodically update our compliance systems. The RFS regulations require the EPA to determine and publish the applicable annual volume and percentage standards for each compliance year by November 30 for the forthcoming year, and such blending percentages could be higher or lower than amounts estimated and accrued for in our consolidated financial statements. The future cost of RINs is difficult to estimate until such time as the EPA finalizes the applicable standards for the forthcoming compliance year. Moreover, in addition to increased price volatility in the RIN market, there have been multiple instances of RINs fraud occurring in the marketplace over the past several years. The EPA has initiated several enforcement actions against refiners who purchase fraudulent RINs, resulting in substantial costs to the refiner. We cannot predict with certainty our exposure to increased RINs costs in the future, nor can we predict the extent by which costs associated with RFS regulations will impact our future results of operations.

The prices of crude oil and refined and finished lubricant products materially affect our profitability, and are dependent upon many factors that are beyond our control, including general market demand and economic conditions, seasonal and weather-related factors, regional and grade differentials and governmental regulations and policies.


Among these factors is the demand for crude oil and refined and finished lubricant products, which is largely driven by the conditions of local and worldwide economies, as well as by weather patterns, changes in consumer preferences and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, and more recently in response to the COVID-19 pandemic, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, crude oil differentials (including regional and grade differentials), changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve, global market conditions, actions by foreign nations and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined and finished lubricant products can also be reduced due to a local or national recession or other adverse economic condition, thatwhich 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 gas/electric hybrid 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.


24
Table of Content

We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. For example, the reversal of certain existing pipelines or the construction of certain new pipelines transporting additional crude oil or refined products to markets that serve competing refineries could affect the market dynamic that has allowed us to take advantage of favorable pricing. Also, in December 2015, the U.S. Congress lifted the ban on the ability of producers to export domestic crude oil. This could potentially impact crack spreads and price differentials between domestic and foreign crude oils. A deterioration of crack spreads or price differentials between domestic and foreign crude oils could have a material adverse effect on our business, financial condition, results of operations and cash flows.


Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year and can vary year to year in the event of unseasonably cool weather in the summer months and / and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products. In general, prices for refined products are influenced by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on operating results, therefore, depends in part on how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings and cash flow. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial condition and results of operations. Also, our crude oil and refined products inventories are valued at the lower of cost or market under the last-in, first-out (“LIFO”) inventory valuation methodology. If the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of products sold even when there is no underlying economic impact at that point in time. Continued volatility in crude oil and refined products prices could result in lower of cost or market inventory charges in the future, or in reversals reducing cost of products sold in subsequent periods should prices recover. For example, we recorded a charge and increase to cost of products sold in the amount of $78.5 million and a non-cash decrease to cost of products sold in the amount of $108.7 million and $291.9$119.8 million for the years ended December 31, 20172020 and 2016,2019, respectively.


To successfully operate our facilities, we are required to expend significant amounts for capital outlays and operating expenditures. If we are unable to complete capital projects at their expected costs or in a timely manner, 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.

Our facilities consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our facilities by installing new equipment and redesigning older equipment to improve refinery capacity or to address changes in consumer preferences, such as the growing demand for renewable diesel and other lower carbon fuels. The installation and redesign of key equipment at our facilities, including the conversion of our Cheyenne Refinery to renewable diesel production and the construction of the renewable diesel and pre-treatment units at our Artesia facility, involves significant uncertainties, including the following: our upgraded equipment may not perform at expected levels; operating costs of the upgraded equipment may be higher than expected; the yield and product quality of new equipment may differ from design and/or specifications and redesign, modification or replacement of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future financial condition and results of operations. In the third quarter of 2020, we permanently ceased refining operations at our Cheyenne Refinery and subsequently began converting certain assets at the Cheyenne Refinery to renewable diesel production due, in part, to uncompetitive operating and maintenance costs for the refinery.

One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the conversion or expansion of existing ones, such as the conversion of the Cheyenne Refinery to renewable diesel production and the connection of a new renewable diesel and a pre-treatment unit at the Navajo Refinery. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements or take advantage of new government incentive programs, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets, including the growing demand for renewable diesel and other lower carbon fuels. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including:
25
Table of Content

•third party challenges to, denials, or delays with respect to the issuance of requisite regulatory approvals and/or obtaining or renewing permits, licenses, registrations and other authorizations;
•societal and political pressures and other forms of opposition;
•compliance with or liability under environmental 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, terrorists or cyberattacks, domestic vandalism or other events (such as equipment malfunctions, explosions, fires, 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.

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.Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, the construction of our previously announced renewable diesel units and pre-treatment unit at our Cheyenne and Artesia facilities 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 or renewable diesel in a region in which such growth does not materialize. As a result, new capital investments may not achieve our expected investment return, which could adversely affect our financial condition or results of operations.

In addition, we expect to execute turnarounds at our refineries, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime.

Our forecasted internal rates of return are also based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply, global market conditions, actions by foreign nations and customer demand.

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, as well as certain developments in the global oil markets, have had and may continue to have a material adverse effect on our operations, business, financial condition and results of operations and cash flows.

Our success depends on the demand for petroleum products such as transportation fuels and finished lubricant products, which is largely driven by the conditions of local and worldwide economies, and the supply of crude oil and other feedstocks. COVID-19’s spread across the globe and governmental actions in response thereto have negatively affected worldwide economic and commercial activity, significantly reduced global demand for oil, gas and refined products, and created significant volatility and disruption of financial and commodity markets in the first half of 2020. Other factors currently impacting crude oil supply include production levels implemented by OPEC members, other large oil producers such as Russia and domestic and Canadian oil producers. The oversupply of crude oil in the market has caused certain domestic and Canadian oil producers from whom we source crude oil to shut-in their production, which could impact our ability to readily source crude oil once the stored crude oil is depleted. While demand for refined products stabilized in the second half of 2020, this combination of events contributed to an overall drop in prices, as well as a lack of forward visibility in demand, for crude oil and refined products in 2020. See “Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Impact of COVID-19 on Our Business” for additional discussion of the impact of COVID-19 on our business.

In addition, the supply and demand for refined and finished lubricant products depends on many other factors outside of our control, some of which include:

•changes in domestic and international demand for, and the marketability of, our refined and finished lubricant products due to governmental actions, including travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, which could result in a full or partial shutdown of our facilities;
•increased price volatility, including the price we receive for refined and finished lubricant products;
•the health of our workforce, including contractors and subcontractors, and their access to our facilities, which could result in a full or partial shutdown of our facilities if a significant portion of the workforce at a facility is impacted;
26
Table of Content
•the availability, distribution and effectiveness of vaccines for COVID-19;
•the ability or willingness of our vendors and suppliers to provide the equipment, parts, crude oil or other raw materials for our operations or otherwise fulfill their contractual obligations, which could reduce our production levels or otherwise cause our delay or failure to deliver refined or other finished lubricant products timely or at all or cause delay or failure to complete projects at our facilities;
•the ability or willingness of our customers to fulfill their contractual obligations or any material reduction in, or loss of, revenue from our customers;
•increased potential for the occurrence of operational hazards, including terrorism, cyberattacks or domestic vandalism, as well as information system failures or communication network disruptions;
•increased cost and reduced availability of capital for growth or capital expenditures;
•availability and operability of terminals, tankage and pipelines that store and transport crude oil and refined and finished lubricant products;
•delay by government authorities in issuing or maintaining permits necessary for our business or our capital projects;
•shareholder activism and activities by non-governmental organizations to limit sources of funding for the energy sector;
•increased costs of operation in relation to the COVID-19 outbreak, which costs may not be fully recoverable or adequately covered by insurance; and
•the impact of any economic downturn, recession or other disruption of the U.S. and global economies and financial and commodity markets.

The spread of COVID-19 has caused us to significantly modify our business practices (including limiting employee and contractor presence at our work locations, restricting travel unless approved by senior leadership, quarantining employees when necessary, reducing our expected total consolidated capital expenditures for 2020 and reducing utilization at our refineries), and we may take further actions as may be required by government authorities or that we determine are in the best interests of our employees, contractors, customers, suppliers and communities. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, and our ability to perform critical functions could be adversely impacted. In addition, deterioration in gross margins and the economic slowdown resulting from the COVID-19 pandemic was a contributing factor in certain goodwill and long-lived asset impairments we recorded in 2020. See “An impairment of our goodwill or long-lived assets could reduce our earnings or negatively impact our financial condition and results of operations” for further discussion of the impairment risk in our business and the impairments we recorded in 2020. A reasonable expectation exists that further deterioration in gross margins or a prolonged economic slowdown due to the COVID-19 pandemic could result in an additional impairment of assets or of goodwill at some point in the future. Such impairment charges could be material.

The effects of COVID-19 are difficult to predict and the duration of any potential business disruption or the extent to which it may negatively affect our operating results is uncertain. Any additional impact will depend on future developments and new information that may emerge regarding the spread, severity and duration of the COVID-19 pandemic and the actions taken by authorities to contain it or manage its impact, all of which are beyond our control. In addition, if the volatility and seasonality in the oil and gas industry were to increase, the demand for our products and the prices that we will be able to charge for those products may decline. We continue to monitor the situation to assess further possible implications to our business and to take actions in an effort to mitigate adverse consequences. The effects of the COVID-19 pandemic, as well as the volatility in global oil markets, 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 dividends to our shareholders.

Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.

We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry.

We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

27
Table of Content
In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us.

The markets in which we compete may be impacted by competitors' plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability.

Also, the potential operation of new or expanded refined product transportation pipelines, or the conversion of existing pipelines into refined product transportation pipelines, could impact the supply of refined products to our existing markets and negatively affect our profitability.

In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States.

The market for our lubricants and specialty products segment is highly competitive and requires us to continuously develop and introduce new products and product enhancements.

Our ability to grow our Lubricants and Specialty Products segment depends, in part, on our ability to continuously develop, manufacture and introduce new products and product enhancements on a timely and cost-effective basis, in response to customers’ demands for higher performance process lubricants, coatings, greases and other product offerings. Our competitors may develop new products or enhancements to their products that offer performance, features and lower prices that may render our products less competitive or obsolete, and, as a consequence, we may lose business and/or significant market share. Our efforts to respond to changes in consumer demand in a timely and cost-efficient manner to drive growth could be adversely affected by unfavorable margins or difficulties or delays in product development and service innovation, including the inability to identify viable new products, successfully complete research and development, obtain regulatory approvals, obtain intellectual property protection or gain market acceptance of new products or service techniques. The development and commercialization of new products require significant expenditures over an extended period of time, and some products that we seek to develop may never become profitable, and we could be required to write-off our investments related to a new product that does not reach commercial viability.

A disruption to or proration of the refined product distribution systems or manufacturing facilities we utilize could negatively impact our profitability.

We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by the El Dorado, Navajo, Woods Cross, and Tulsa Refineries are NuStar Energy and Magellan, SFPP and Plains, Chevron and UNEV, and Magellan, respectively.

Our U.S. refineries also utilize systems owned by HEP. If these key pipelines or their associated tanks and terminals become inoperative or decrease the capacity available to us, we may not be able to sell our product, or we may be required to hold our product in inventory or supply products to our customers through an alternative pipeline or by rail or additional tanker trucks from the refinery, all of which could increase our costs and result in a decline in profitability.

We have manufacturing facilities in foreign countries that support the Lubricants and Specialty Products segment. If one of our facilities is damaged or disrupted, resulting in production being halted for an extended period, we may not be able to timely supply our customers. We take steps to mitigate this risk, including business continuity and contingency planning and procuring property insurance (including business interruption) and casualty insurance. Nevertheless, the loss of sales in any one region over an extended period of time could have a material adverse effect on our business, financial condition and results of operations.

28
Table of Content
A material decrease in the supply of crude oil or other raw materials available to our refineries and other facilities could significantly reduce our production levels and negatively affect our operations.


To maintain or increase production levels at our refineries, we must continually contract for crude oil supplies from third parties. There are a limited number of crude oil suppliers in certain geographic regions, and in such cases, we may be required to source from a single third party supplier. If we are unable to maintain or extend our existing contracts with any such crude oil suppliers, or enter into new agreements on similar terms, the supply of crude oil could be adversely impacted, or we may incur a higher cost. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines, catastrophic events or otherwise, could result in a decline in the volume of crude oil available to our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries or the potential operation of a new, converted or expanded crude oil pipeline that transports crude oil to other markets could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries' production capacities.


For certain raw materials and utilities used by our refineries and other facilities, there are a limited number of suppliers and, in some cases, we source from a single supplier and/or suppliers in economies that have experienced instability or the supplies are specific to the particular geographic region in which a facility is located. Any significant disruption in supply could affect our ability to obtain raw materials, or increase the cost of such raw materials, which could significantly reduce our production levels or have a material adverse effect on our business, financial condition and results of operations. In addition, certain raw materials that we use are subject to various regulatory laws, and a change in the ability to legally use such raw materials may impact our liquidity, financial position and results of operations.

It is also common in the refining industry for a facility to have a sole, dedicated source for its utilities, such as steam, electricity, water and gas. Having a sole or limited number of suppliers may limit our negotiating power, particularly in the case of rising raw material costs. Any new supply agreements we enter into may not have terms as favorable as those contained in our current supply agreements.


Additionally, there is growing concern over the reliability of water sources. The decreased availability or less favorable pricing for water as a result of population growth, drought or regulation could negatively impact our operations.


If our raw material, utility or water supplies were disrupted, our businesses may incur increased costs to procure alternative supplies or incur excessive downtime, which would have a direct negative impact on our operations.


We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries, and we own a significant equity interest in HEP.

At December 31, 2020, we owned a 57% limited partner interest and a non-economic general partner interest in HEP. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Idaho, Kansas, Nevada, New Mexico, Oklahoma, Texas, Utah, Washington and Wyoming and refinery units in Kansas and Utah. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, leasing certain pipeline capacity to third parties, charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves the El Dorado, Navajo, Woods Cross and Tulsa Refineries under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2022 through 2036 serves the El Dorado Refinery under long-term tolling agreements expiring in 2030 and serves the Woods Cross Refinery under long-term tolling agreements expiring in 2031. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to:

•its reliance on its significant customers, including us;
•competition from other pipelines;
•environmental regulations affecting pipeline operations;
•operational hazards and risks;
•pipeline tariff regulations affecting the rates HEP can charge;
•limitations on additional borrowings and other restrictions due to HEP's debt covenants; and
•other financial, operational and legal risks.

29
Table of Content

We may not be able to successfully execute our business strategies to grow our business.Further, if we are unable to complete capital projects at their expected costsThe occurrence of any of these risks could directly or in a timely manner, if we are unsuccessful in integrating the operations of assets we acquire, or if the market conditions assumed in our project economics deteriorate,indirectly affect HEP's as well as our financial condition, results of operations orand cash flows as HEP is a consolidated VIE. Additionally, these risks could be materiallyaffect HEP's ability to continue operations which could affect their ability to serve our supply and adversely affected.distribution network needs.


OneWhile we own a 57% limited partner interest and a non-economic general partner interest in HEP, HEP is a publicly-traded master limited partnership and is a legally distinct entity. Conflicts of the ways weinterest may grow our business is through the construction of new refinery processing units (or the purchasearise between us and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most ofHEP, which are not fully within our control, including:

third party challenges to, denials, or delays with respect to the issuance of requisite regulatory approvals and/or obtaining or renewing permits, licenses, registrations and other authorizations;
societal and political pressures and other forms of opposition;
compliance with or liability under environmental 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, or other events (such as equipment malfunctions, explosions, fires, 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.

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.Delays in making required changes or upgrades to our facilities couldmay subject us to fines or penalties as well as affect our abilityclaims from HEP's public unitholders.

For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” For risks related to supply certain products we make. In addition, our revenues may not increase immediately uponHEP's business, see Item 1A of HEP's Annual Report on Form 10-K for the expenditurefiscal year ended December 31, 2020.

Our acquisition strategy involves numerous risks, any of funds on a particular project. For instance, if we build a new refinery processing unit, 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 capital investments may not achieve our expected investment return, which could adversely affect our financial condition or results of operations.us.

Our forecasted internal rates of return are also based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply and customer demand.


An additional component of our growth strategy is to selectively acquire complementary assets or businesses for our refining operations in order to increase earnings and cash flow. Our ability to do so will be dependent upon a number of factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and other factors beyond our control. Risks associated with acquisitions include those relating to:


•diversion of management time and attention from our existing business;
•challenges in managing the increased scope, geographic diversity and complexity of operations and inefficiencies that may result therefrom;
•difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
•liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
•greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
•difficulties or delays in achieving anticipated operational improvements or benefits;benefits or inaccurate assumptions about future synergies or revenues;
•incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
•issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.


Any acquisitions that we do consummate may have adverse effects on our business and operating results.


TableAn impairment of Content

Currency fluctuationsour goodwill or devaluations maylong-lived assets could reduce our earnings or negatively impact our operatingfinancial condition and results. of operations.


Fluctuations or devaluations in foreign currencies relative to the U.S. dollar can impact our revenue and our costs of doing business. MostAn impairment of our products and services are sold through contracts denominated in U.S. dollars; however, some ofgoodwill or long-lived assets could reduce our revenue, local expenses and manufacturing costs are incurred in local currencies and, therefore, changes in the exchange rates between the U.S. dollar and foreign currencies can increaseearnings or decrease our revenue and expenses reported in U.S. dollars and maynegatively impact our results of operations. Any significant changeoperations 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 goodwill or long-lived asset 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 goodwill and long-lived assets impairment analyses are sensitive to changes in key assumptions used in our analysis, estimates of future crack spreads, forecasted production 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 goodwill or long-lived assets in the future.

30
Table of Content
As market prices for refined products and market prices for crude oil continue to fluctuate, we will need to continue to evaluate the carrying value of our refinery reporting units. During the currenciesyear ended December 31, 2020, we recorded long-lived asset impairment charges of $232.2 million that related to our Cheyenne Refinery, $26.5 million for construction-in-progress consisting primarily of engineering work for potential upgrades to certain processing units at our Tulsa and El Dorado Refineries and $204.7 million related to PCLI. Also, during the year ended December 31, 2020, we recorded a goodwill impairment charge of $81.9 million that related to Sonneborn. A reasonable expectation exists that further deterioration in our operating results or overall economic conditions could result in an impairment of goodwill and / or additional long-lived asset impairments at some point in the future. Future impairment charges could be material to our results of operations and financial condition.

Potential product, service or other related liability claims and litigation could adversely affect our business, reputation and results of operations.

A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the countriesproducts loaded at our loading racks. If our quality control measures were to fail, we may have contaminated or off-specification commingled pipelines and storage tanks or off-specification product could be sent to public gasoline stations. The development, manufacture and sale of specialty lubricant products also involves an inherent risk of exposure to potential product liability claims. These types of incidents could result in which we do businessproduct liability claims from our customers. Our Lubricants and Specialty Products segment could also be subject to false advertising claims, product recalls, workplace exposure, product seizures and related adverse publicity.

Any of these incidents is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the U.S. dollar could affect our competitiveness and controluse of our cost structure, which couldor exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business, reputation or results of operations or our ability to maintain existing customers or retain new customers. Although we maintain product and other general liability insurance, there can be no assurance that the types or levels of coverage maintained are adequate to cover these potential risks, or that we will be able to continue to maintain existing insurance or obtain comparable insurance at a reasonable cost, if at all.

We sell many of our lubricants and specialty products through distributors, which presents risks that could adversely affect our operating results.

A large portion of our lubricants and specialty product sales, both in domestic and international markets, occur through distributors. As a result, we are dependent on these distributors to promote and create demand for our products. We cannot assure you that we will be successful in maintaining and strengthening our relationships with our distributors or establishing relationships with new distributors who have the ability to market, sell and support our products effectively. We may rely on one or more key distributors for a product or a region, and the loss of these distributors could reduce our revenue. The sales, business practices and reputation of our distributors may affect our business and our reputation. The consolidation of distributors, loss of a relationship with a distributor, significant disagreement with a distributor, or significant deterioration in the financial condition of a distributor could also have an adverse effect on our operating results and may also result in increased competition in the applicable jurisdiction.

Our hedging transactions may limit our gains and expose us to other risks.

We periodically enter into derivative transactions as it relates to inventory levels and/or future production to manage the risks from changes in the prices of crude oil, refined products and other feedstocks. These transactions limit our potential gains if commodity prices move above or below the certain price levels established by our hedging instruments. We hedge price risk on inventories above our target levels to minimize the impact these price fluctuations have on our earnings and cash flows. Consequently, our hedging results may fluctuate significantly from one reporting period to the next depending on commodity price fluctuations and our relative physical inventory positions. These transactions may also expose us to risks of financial losses; for example, if our production is less than we anticipated at the time we entered into a hedge agreement or if a counterparty to our hedge agreements fails to perform its obligations under the agreements.

31
Table of Content
RISKS RELATED TO GOVERNMENT REGULATION

There are various risks associated with greenhouse gases and climate change that could result in increased operating costs and litigation and reduced demand for the refined products we produce and investment in our industry.

Climate change continues to attract considerable attention in the United States, Canada, Europe, and other regions. 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, or “GHGs”, to restrict or eliminate such future emissions, and to require or incentivize the use of lower-carbon or renewable alternatives. As a result, our operations are subject to a series of regulatory, political, litigation, and financial risks associated with the refining of petroleum products and emission of GHGs.

The EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. The U.S. Supreme Court has also found that GHG emissions constitute a pollutant under the CAA. Accordingly, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas sources in the United States or to control or reduce emissions of GHGs, including methane, from such sources. In addition, the EPA, together with the DOT, implement GHG emission and corporate average fuel economy standards for vehicles manufactured in the United States. Moreover, on January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across governmental agencies and economic sectors. 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 GHG cap and trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates and combustion engine phaseouts. Similar such regulations exist at the provincial and federal levels in Canada, including a nation-wide greenhouse gas pricing initiative and regulations related to the control of GHGs from automobiles and light duty trucks and either cap and trade programs or carbon taxes in the provinces of Quebec, Ontario, and Alberta. The Netherlands also participates in certain European legal initiatives, including GHG cap and trade programs, and the Climate Act with the goal of significantly reducing GHG emissions by 49% (compared to 1990) by 2030 and by at least 95% (compared to 1990) by 2050. The Climate Act also establishes that the government must prepare a Climate Plan. The first Climate Plan covers the period between 2021 and 2030. This plan contains, amongst others, the principles by which the government intends to achieve the goals set out in the Climate Act. It is unclear what further measures the Dutch government will take to reduce GHG emissions pursuant to this law. At the international level, the United Nations-sponsored “Paris Agreement” calls for member nations to limit their GHG emissions through nationally-determined reduction goals reevaluated every five years after 2020. The United States initially joined and then withdrew from such agreement, effective November 4, 2020. Under the new administration, the United States rejoined the agreement effective February 19, 2021 and has instructed the federal government to begin formulating the United States' emissions reduction goal. EU member states have agreed to reduce emissions by at least 40% by 2030. The Netherlands target is 49% reduction in GHG emissions by 2030.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the refined products that we produce. Additionally, political, litigation and financial risks may result in curtailed refinery activity, incurred liability, or other adverse effects on our business, financial condition and results of operations.


There are also increasing risks of litigation related to climate change effects. Governments and third-parties have brought suit against some fossil fuel companies alleging, among other things, that such companies created public and private nuisances by producing fuels that contributed to climate change, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. While we are not party to such suits at this time, we may become subject to such litigation in the future. Such cases could also adversely impact public perception and the demand for fossil fuels and petroleum products, which could subsequently result in decreased demand for our services and refined products and a drop in our share price.

32
Table of Content
Our share price could be adversely impacted if existing shareholders, including institutional investors, elect in the future to shift some or all of their investments into renewable energy or non-energy related sectors based on social and environmental considerations. Additionally, in recent years institutional lenders have become more attentive to sustainable lending practices and have been lobbied intensively, and often publicly, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities, could result in a reduction of available capital funding for potential development projects and could also adversely affect demand for our services and refined products, all of which could impact our future financial results.

The availability and cost of renewable identification numbers and other required credits could have an adverse effect on our financial condition and results of operations.

Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS regulations reflecting the increased volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as RINs, in lieu of such blending. We currently purchase RINs for some fuel categories on the open market in order to comply with the quantity of renewable fuels we are exposedrequired to fluctuationsblend under the RFS regulations. Since the EPA first began mandating biofuels in foreign currency exchange rates, particularlyexcess of the “blend wall” (the 10% ethanol limit prescribed by most automobile warranties), the price of RINs has been extremely volatile. While we cannot predict the future prices of RINs, the costs to obtain the necessary number of RINs could be material. If we are unable to pass the costs of compliance with the RFS regulations on to our customers, if sufficient RINs are unavailable for purchase, if we have to pay a significantly higher price for RINs or if we are otherwise unable to meet the RFS mandates, our financial condition and results of operations could be adversely affected.

In the past, we have received small refinery exemptions under the RFS program for certain of our refineries. However, there is no assurance that such an exemption will be obtained for any of our refineries in future years. For example, the EPA has recently indicated it plans to more closely align the agency’s criteria for granting small refinery exemptions with the recommendation of the Department of Energy, which could result in fewer such exemptions being granted. The failure to obtain such exemptions for certain of our refineries could result in the need to purchase more RINs than we currently have estimated and accrued for in our consolidated financial statements. EPA recently promulgated new RFS regulations that could require the agency to increase the volume of renewable fuel or RINs that refiners are required to purchase if the agency anticipates it will grant small refinery exemptions. This also could increase the number of RINs we need to purchase. Additionally, a recent decision by the U.S. Court of Appeals for the 10th Circuit vacated two small refinery exemption decisions for the 2016 compliance year and remanded the case to the EPA for further proceedings. That decision is before the Supreme Court for further review. It is not clear at this time what steps the EPA will take with respect to our 2016 small refinery exemptions, or how the Canadian dollar,case will impact future small refinery exemptions.

In addition, the euroRFS regulations are highly complex and evolving, requiring us to periodically update our compliance systems. The RFS regulations require the Chinese renminbi. We recognize foreign currency transaction gainsEPA to determine and losses arising frompublish the applicable annual volume and percentage standards for each compliance year by November 30 for the forthcoming year, and such blending percentages could be higher or lower than amounts estimated and accrued for in our operationsconsolidated financial statements. The future cost of RINs is difficult to estimate until such time as the EPA finalizes the applicable standards for the forthcoming compliance year, but the EPA does not always do so by the statutory deadline. Moreover, in addition to increased price volatility in the period incurred. As a result, currency fluctuations betweenRINs market, there have been multiple instances of RINs fraud occurring in the U.S. dollar andmarketplace over the currenciespast several years. The EPA has initiated several enforcement actions against refiners who purchase fraudulent RINs, resulting in which we do business have caused and will continuesubstantial costs to cause foreign currency transaction and translation gains and losses, which could be material.the refiner. We cannot predict with certainty our exposure to increased RINs costs in the effects of exchange rate fluctuations uponfuture, nor can we predict the extent by which costs associated with RFS regulations will impact our future operating results because of the number of currencies involved, the variability of currency exposures and the potential volatility of currency exchange rates

Our business is subject to the risks of international operations.


33
Table of Content
We derive a portion of our revenueincur significant costs, and earnings from international operations. Compliance with applicable U.S. and foreign laws and regulations, such as import and export requirements, anti-corruption laws, foreign exchange controls and cash repatriation restrictions, data privacy requirements, environmental laws, labor laws and anti-competition regulations, increasesexpect to incur additional costs in the cost of doing business in foreign jurisdictions. Although we have implemented policies and proceduresfuture, to comply with these lawsexisting, new and regulations, a violation by any of our employees, contractors or agents could nevertheless occur. In some cases, compliance with the laws and regulations of one country could violate the laws and regulations of another country. Violations of these laws and regulations could materially adversely affect our company's brand, international growth efforts and business.

We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters.


Our refineryOperations of our facilities and pipeline operationspipelines are subject to international, foreign, federal, state, provincial and local laws regulating, among other things, the generation, storage, handling, use, transportation and distribution of petroleum and hazardous substances by pipeline, truck, rail, ship and barge, the emission and discharge of materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of the environment. In addition, as a result of our recent acquisition of PCLI, we have manufacturing and distribution operations in Canadaforeign countries that are subject to Canadian national and provincialthe environmental laws and regulations and similar laws in otherof such foreign countries. Permits or other authorizations are required under these laws for the operation of our refineries,facilities, pipelines and related operations, and these permits and authorizations are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns.shutdowns, and reputational harm. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations. For example, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. The EPAstandards and, in 2018, published a final rule in November 2017 that issued area designations with respect to ground level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable.” In December 2017, the EPA responded to states' preliminary non-attainment designations, and expects to issue final non-attainment designations during the first half of 2018.attainment/nonattainment designations. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Also, in February 2016, a new EPA rule became effective that amends three refinery standards already in effect, imposing additional or, in some cases, new emission control requirements on subject refineries. The final rule requires, among other things, benzene monitoring at the refinery fence line and submittal of fence line monitoring data to the EPA on a quarterly basis; upgraded storage tank controls requirements, including new applicability thresholds; enhanced performance requirements for flares, continuous monitoring of flares and pressure release devices and analysis and remedy of flare release events; and compliance with emissions standards for delayed coking units. Refineries have up to three years from the effective date of the final rule to come into compliance with certain requirements of the rule, such as the performance requirements for flares, while other aspects of the rule require compliance to be achieved at a sooner date. For example, the rule's fence line monitoring requirements became effective January 31, 2018. In July 2016,November 2018, the EPA issued a finale rule providing refiners an additional 18 monthspublished amendments to comply with a small subset of the new rules related to air emissions resulting from startup, shutdownclarify and maintenance events. In December 2016, the EPA granted petitions for reconsideration from industry and environmental organizations on aspects of the rule related to work practice standards
Table of Content

forcorrect certain process units and equipment, as well as fence line monitoring requirements. To date, EPA has not published revised rules. These new rules, as well as subsequent rulemaking under the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years and result in increased costs on our operations. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of our operations and capital requirements.requirements.


As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include, but are not limited to, soil, groundwater and waterway contamination, air pollution, personal injury and property damage allegedly caused by substances which we processed, manufactured, handled, used, released or disposed.


We are and have been the subject of various local, state, provincial, federal, foreign, international and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.


Our operations are also subject to various foreign and domestic laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations but cannot guarantee that these efforts will always be successful. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Failure to appropriately manage occupational health and safety risks associated with our business could also adversely impact our employees, communities, stakeholders, reputation and results of operations.


The costs of environmental and safety regulations are already significant and compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies or courts could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.


From time
34
Table of Content
We are also subject to time,existing, and may in the future be subject to new federalor changing, domestic and foreign energy policy legislation is enacted by the U.S. Congress or the Federal or Provincial Governments of Canada.legislation. For example, in December 2007, the U.S. Congress passedUnited States, the Energy Independence and Security Act which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. InDutch law also focuses on increasing the use of renewal fuels, and in Canada, fuel content legislation also exists at the federal and provincial level. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.


For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.”


The adoptionWe are subject to significant regulation and oversight by governmental agencies.

New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations. Our assets and operations are subject to regulation and oversight by foreign, federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these agencies, have the potential to adversely affect our profitability. In addition, a certain degree of climate change legislationregulatory uncertainty is created by the new administration because it remains unclear specifically what the new administration may do with respect to future policies and regulations that may affect us. Regulation affects almost every part of our business. Furthermore, we could incur additional costs to comply with such statutes, rules, regulations and orders. Should we fail to comply with any applicable statutes, rules, regulations, and orders of regulatory authorities, we could be subject to substantial penalties and fines. New laws, regulations or policy changes sometimes arise from unexpected sources. New laws or regulations, unexpected policy changes or interpretations of existing laws or regulations, applicable to our income, operations, assets or another aspect of our business, could have a material adverse impact on our earnings, cash flow, financial condition and results of operations.

Our business is subject to complex and evolving global laws, regulations and security standards regarding privacy, cybersecurity and data protection (“data protection laws”). Many of these laws are subject to change and uncertain interpretation, and could result in claims, increased operatingcost of operations, or otherwise harm 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 laws could increase the costs and reduced demand forcomplexity of compliance. 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 protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments, and negative publicity, require us to change our business practices, increase the refined products we produce.

The EPA has determined that emissionscosts and complexity of carbon dioxide, methanecompliance, and adversely affect our business. Our compliance with recently enacted laws like the General Data Protection Regulation, and other greenhouse gas emissions,similar privacy/security laws, as well as any associated inquiries or “GHGs,” present an endangermentinvestigations or any other government actions related to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. For example, the EPA adopted rules that require certain large stationary sources to obtain permits to authorize emissions of GHGs. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. Both the EPA and Environment and Climate Change Canada have adopted regulations that limit GHG emissions from automobiles and light-duty trucks, whichlaws, may result in a reduction in demand for the refined products that we produce.increase our operating costs.


35
Table of Content

Although the U.S. Congress has previously considered legislation to reduce GHGIncreases in required fuel economy and regulation of CO2 emissions federal legislative action appears unlikely at this time. Meanwhile, many states have pursued or are considering their own initiatives designed to reduce GHG emissions, such as cap and trade programs, carbon taxes, low carbon fuel standards, and vehicle efficiency standards. Similar measures are being pursued in Canada at the federal and provincial level, and the provinces of Quebec, Ontario, and Alberta have all implemented either cap and trade programs or levied carbon taxes.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and therebyfrom motor vehicles may reduce demand for transportation fuels.

The EPA and the refined productsNational Highway Traffic Safety Administration (“NHTSA”) are required to promulgate requirements regarding the Corporate Average Fuel Economy (“CAFE”) of the nation's passenger fleet. On August 28, 2012, the EPA and NHTSA adopted standards through model year 2025 in two phases. The first phase established final standards for 2017-2021 model year vehicles that we produce. Consequently, legislationare projected to require 40.3 - 41.0 m.p.g. in model year 2021 on an average industry fleet-wide basis. The second phase of the CAFE program represents non-final “augural” standards for 2022-2025 model year vehicles that are projected to require 48.7 - 49.7 m.p.g. in model year 2025 on an average industry fleet-wide basis. However, following the change in presidential administrations, there have been attempts to modify these standards. In August 2018, the EPA and regulatory programsNHTSA proposed the Safer Affordable Fuel Economy Rule which amended the existing CAFE standards and proposed new standards covering model years through 2026. While the EPA issued a rule in September 2019 that seeks to reduce emissionspreempt the ability of GHGsstates to set stricter standards than those set by the federal government, no final rule has yet been issued regarding amendments to the current CAFE standards. All of these rulemakings will likely be subject to challenge by a variety of parties seeking stricter GHG and CAFE standards. Additionally, several states are seeking to promote zero emission vehicles, such as electric vehicles, and to mandate transition away from internal combustion engines. Any increases in fuel economy standards, along with mandated increases in use of renewable fuels discussed above, as well as electric vehicle mandates or combustion engine bans, could result in decreasing demand for petroleum fuels. Decreasing demand for petroleum fuels could have ana material effect on our financial condition and results of operation.

GENERAL RISK FACTORS

Cyberattacks or security breaches could have a material adverse effect on our business, financial condition and results of operations.


Our business is dependent upon information systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. We monitor our information systems on a 24/7 basis in an effort to detect cyberattacks or security breaches. Preventative and detective measures we utilize include independent cybersecurity audits and penetration tests. We implemented these efforts along with other risk mitigation procedures to detect and address unauthorized and damaging activity on our network, stay abreast of the increasing threat landscape and improve our security posture. 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.

Furthermore, we collect and store sensitive data in the ordinary course of our business, including personally identifiable information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. Despite our security measures, our information systems may become the target of cyberattacks or security breaches (including employee error, malfeasance or other breaches), 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 customer or company information and our financial reporting. Even with insurance coverage, a claim could be denied or coverage delayed. A cyber-attack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation or a loss of consumer confidence in our products and services, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations.

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


Our operations are subject to catastrophic losses, operational hazards, and unforeseen interruptions and other disruptive risks such as natural disasters, adverse weather, accidents, maritime disasters (including those involving marine vessels/terminals), fires, explosions, hazardous materials releases, cyber-attacks,terror or cyberattacks, domestic vandalism, power failures, mechanical failures and other events beyond our control. These events could result in an injury, loss of life, property damage or destruction, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments.


36
Table of Content
We may not be able to maintain or obtain insurance 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 situations. As a result of market conditions, premiums and deductibles for certain of 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 all 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. If any refineryof our facilities were to experience an interruption in operations, our earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.


The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. Further, our underwriters could have credit issues that affect their ability to pay claims. If a significant accident or event occurs that is self-insured or not fully insured, it could have a material adverse effect on our business, financial condition and results of operations.

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-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, estimates of future crack spreads, forecasted production 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.

Table of Content

As market prices for refined products and market prices for crude oil continue to fluctuate, we will need to continue to evaluate the carrying value of our refinery reporting units. During the year ended December 31, 2016, we recorded goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million, respectively, on the carrying value of our Cheyenne Refinery. A reasonable expectation exists that future deterioration in gross margins could result in an impairment of goodwill and the long-lived assets of the El Dorado reporting unit at some point in the future. Any additional impairment charges that we may take in the future could be material to our results of operations and financial condition.

Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.

We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry.

We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us.

The markets in which we compete may be impacted by competitors' plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability.

Also, the potential operation of new or expanded refined product transportation pipelines, or the conversion of existing pipelines into refined product transportation pipelines, could impact the supply of refined products to our existing markets and negatively affect our profitability.

In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States.

A disruption to or proration of the refined product distribution systems we utilize could negatively impact our profitability.

We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by the Cheyenne, El Dorado, Navajo, Woods Cross, and Tulsa Refineries are Rocky Mountain, NuStar Energy, SFPP and Plains, Chevron, and Magellan, respectively. All five refineries also utilize systems owned by HEP. If these key pipelines or their associated tanks and terminals become inoperative or decrease the capacity available to us, we may not be able to sell our product, or we may be required to hold our product in inventory or supply products to our customers through an alternative pipeline or by rail or additional tanker trucks from the refinery, all of which could increase our costs and result in a decline in profitability.


We may be subject to information technology system failures, communications network disruptions and breachesdata breaches.

We depend on the efficient and uninterrupted operation of hardware and software systems and infrastructure, including our operating, communications and financial reporting systems. These systems are critical in data security.

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 monitormeeting customer expectations, effectively tracking, maintaining and control pipeline operations could disruptoperating our operations by impedingequipment, directing and compensating our processing of transactions,employees, and interfacing with our abilityfinancial reporting system. We have implemented safeguards and other preventative measures to protect customer or companyour systems and data, including sophisticated network security and internal control measures; however, our information technology systems and communications network, and those of our financial reporting. Our computer systems, including our back-up systems, could be damaged or interruptedinformation technology and communication service providers, remain vulnerable to interruption by fire, earthquake, power outages, computer andloss, telecommunications failure, terrorist attacks, Internet failures, computer viruses, internalmalware, cyberattacks, data breaches and other events unforeseen or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors bygenerally beyond our employees. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and results of operations.control.

Table of Content


We may not be able to obtain funding on acceptable terms or at 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. Recently, the equity and debt markets for many energy industry companies have been adversely affected by low oil prices. 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 at all and reduce, or in some cases cease to provide, funding to borrowers. In addition, lending counterparties under any existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations, or we may experience a decrease in our capacity to issue debt or obtain commercial credit or a deterioration in our credit profile, including a rating agency lowering or withdrawing of our credit ratings if, in its judgment, the circumstances warrant. 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 or we may be required to sell assets. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or construction projects, take advantage of other business opportunities or respond to competitive pressures, comply with regulatory requirements, or meet our short-term or long-term working capital requirements, any of which could have a material adverse effect on our revenues and results of operations. Failure to comply with regulatory requirements in a timely manner or meet our short-term or long-term working capital requirements could subject us to regulatory action.

37
Table of Content
We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries, and we own a significant equity interest in HEP.

At December 31, 2017, we owned a 59% limited partner interest and a non-economic general partner interest in HEP. HEP operates a system of crude oil and petroleum product pipelines; distribution terminals and refinery tankage in Arizona, Idaho, Kansas, Nevada, New Mexico, Oklahoma, Texas, Utah, Washington and Wyoming and refinery units in Kansas and Utah. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, leasing certain pipeline capacity to Delek, charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves the Cheyenne, El Dorado, Navajo, Woods Cross and Tulsa Refineries under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2020 through 2036, serves the El Dorado Refinery under long-term tolling agreements expiring in 2030 and serves the Woods Cross Refinery under long-term tolling agreements expiring in 2031. Furthermore, our financial statements include the consolidated results of HEP. HEPOur business is subject to its own operatingthe risks of international operations, including currency fluctuations

We derive a portion of our revenue and regulatoryearnings from international operations. Our acquisitions of Petro-Canada Lubricants and Sonneborn have expanded our operations and sales in foreign countries and correspondingly may increase our exposure to foreign exchange risks. Any significant change in the value of the currencies of the countries in which we do business against the U.S. dollar could affect our revenue, competitiveness and cost of doing business, which could have a material adverse effect on our business, financial condition and results of operations.

In addition, compliance with applicable U.S. and foreign laws and regulations, such as import and export requirements, anti-corruption laws, data privacy regulations and foreign exchange controls and cash repatriation restrictions, environmental laws, labor laws and anti-competition regulations, increases the cost of doing business in foreign jurisdictions. Although we have implemented policies and procedures to comply with these laws and regulations, a violation by any of our employees, contractors, distributors or agents could nevertheless occur. In some cases, compliance with the laws and regulations of one country could violate the laws and regulations of another country. Violations of these laws and regulations could materially adversely affect our company's brand, international growth efforts and business.

In addition, global market risks, including, but not limited to:

its reliance on its significant customers, including us;
competition from other pipelines;
environmental regulations affecting pipeline operations;
operational hazards and risks;
pipeline tariff regulations affecting the rates HEP can charge;
limitations on additional borrowingsactions by foreign nations and other restrictions due to HEP's debt covenants;international conditions, particularly in a time of increasing economic and global instability, may have a material adverse effect on our results and operations. The consequences of such uncertainty cannot be anticipated or quantified.
other financial, operational and legal risks.

The occurrence of any of these risks could directly or indirectly affect HEP's as well as our financial condition, results of operations and cash flows as HEP is a consolidated VIE. Additionally, these risks could affect HEP's ability to continue operations which could affect their ability to serve our supply and distribution network needs.

For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” For risks related to HEP's business, see Item 1A of HEP's Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

We are exposed to the credit risks, and certain other risks, of our key customers and vendors.


We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We derive a significant portion of our revenues from contracts with key customers.

Table of Content


If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.


Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows.


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 impacts of terrorist attacks and the threat of future terrorist attacks (including cyber-attacks) on the energy transportation industry in general, and on us in particular, are unknown. Increased security measures taken by us as a precaution against possible terrorist attacks or domestic 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. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.


Changes in the insurance markets attributable to terrorist attacks and domestic vandalism 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, vandalism or war could also affect our ability to raise capital including our ability to repay or refinance debt.


Increases in required fuel economy and regulation of CO2 emissions from motor vehicles may reduce demand for transportation fuels.

In 2010, the EPA and the National Highway Traffic Safety Administration (“NHTSA”) finalized new standards, raising the required Corporate Average Fuel Economy (“CAFE”) of the nation's passenger fleet by 40% to approximately 35 miles per gallon (“m.p.g.”) by 2016 and imposing the first-ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and the Department of Transportation finalized first-time standards for fuel economy of medium and heavy duty trucks. On August 28, 2012, the EPA and NHTSA adopted standards through model year 2025 in two phases. The first phase establishes final standards for 2017-2021 model year vehicles that are projected to require 40.3 - 41.0 m.p.g. in model year 2021 on an average industry fleet-wide basis. The second phase of the CAFE program represents non-final “augural” standards for 2022-2025 model year vehicles that are projected to require 48.7 - 49.7 m.p.g. in model year 2025, on an average industry fleet-wide basis. In 2017, the EPA and NHTSA announced that the agencies were reconsidering the second phase CAFE standards, which could result in maintaining the first phase standards for the 2022-2025 model years. A final decision is expected during the first half of 2018. Any increases in fuel economy standards, along with mandated increases in use of renewable fuels discussed above, could result in decreasing demand for petroleum fuels. Decreasing demand for petroleum fuels could have a material effect on our financial condition and results of operation.

To successfully operate our petroleum refining facilities, we are required to expend significant amounts for capital outlays and operating expenditures.

The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related facilities. We are dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future major capital investment, various environmental compliance related projects, regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.

Table of Content

Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; operating costs of the upgraded equipment may be higher than expected; the yield and product quality of new equipment may differ from design and/or specifications and redesign, modification or replacement of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future financial condition and results of operations.

In addition, we expect to execute turnarounds at our refineries, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime.

We may be unable to pay future dividends.


We will only be able to pay dividends from our available cash on hand, cash from operations or borrowings under our credit agreement. The declaration of future dividends on our common stock is evaluated quarterly and will be at the discretion of our board of directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital requirements, and restrictions in our debt agreements and legal requirements. We cannot assure you that any dividends will be paid or the frequency or amounts of such payments.

38
Table of Content
Product liability claims and litigation could adversely affect
We may be unable to adequately protect our intellectual property, which may increase our cost of doing business or otherwise hurt our ability to compete in the market.

We use intellectual property in the ordinary course of our business, including trademarks, trade secrets, copyrighted work and innovations, some of which is material to our business. We take measures to identify and protect our intellectual property through practices appropriate for securing and protecting exclusive rights in and to our intellectual property, including applying for registrations in the United States and in various foreign countries. Despite our efforts to protect such intellectual property, it is possible that competitors or other unauthorized third parties may obtain, copy, use or disclose our trademarks (or other marks likely to cause confusion among our consumers), technologies, products and processes. In addition, the laws and/or judicial systems and enforcement mechanisms of foreign countries in which we create, market and sell our products may afford little or no effective protection of our intellectual property. We may also be subject to infringement complaints from others challenging our use of a technology. We cannot guarantee that our efforts to enforce our intellectual property rights against unauthorized use and appropriation, or our efforts to defend against third party claims of infringement would be successful. These potential risks to our intellectual property could subject us to increased competition and negatively impact our liquidity, financial position and results of operations.

A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the products loaded at our loading racks. If our quality control measures were to fail, we may have contaminated or off-specification commingled pipelines and storage tanks or off-specification product could be sent to public gasoline stations. These types of incidents could result in product liability claims from our customers.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations or our ability to maintain existing customers or retain new customers.

Our hedging transactions may limit our gains and expose us to other risks.

We periodically enter into derivative transactions as it relates to inventory levels and/or future production to manage the risks from changes in the prices of crude oil, refined products and other feedstocks. These transactions limit our potential gains if commodity prices move above or below the certain price levels established by our hedging instruments. We hedge price risk on inventories above our target levels to minimize the impact these price fluctuations have on our earnings and cash flows. Consequently, our hedging results may fluctuate significantly from one reporting period to the next depending on commodity price fluctuations and our relative physical inventory positions. These transactions may also expose us to risks of financial losses; for example, if our production is less than we anticipated at the time we entered into a hedge agreement or if a counterparty to our hedge agreements fails to perform its obligations under the agreements.


Changes in our credit profile, or a significant increase in the price of crude oil, may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and limit our ability to purchase sufficient quantities of crude oil to operate our refineries at desired capacity.


An unfavorable credit profile, or a significant increase in the price of crude oil, could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us or require credit enhancement. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms or credit enhancement requirements on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our refineries at desired capacity. A failure to operate our refineries at desired capacity could adversely affect our profitability and cash flow.

Table of Content


Our credit facility contains certain covenants and restrictions that may constrain our business and financing activities.


The operating and financial restrictions and covenants in our credit facility and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our revolving credit facility imposes usual and customary requirements for this type of credit facility, including: (i) limitations on liens and indebtedness; (ii) a prohibition on changes in control and (iii) restrictions on engaging in mergers and consolidations. If we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the credit facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to obtain, sufficient funds to make these immediate payments. If we desire to undertake a transaction that is prohibited by the covenants in our credit facility, we will need to obtain consent under our credit facility. Such refinancing may not be possible or may not be available on commercially acceptable terms.


Our business may suffer due to a departure of any of our key senior executives or other key employees. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.


Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key manperson life insurance, non-compete agreements, or employment agreements with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.


Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations.


39
Table of Content
A portion of our workforce is unionized, and any disruptions in our labor force or adverse employee relations could adversely affect our business.

We depend on unionized labor for the operation of many of our facilities. As of December 31, 2017,2020, approximately 33%29% of our employees were represented by labor unions under collective bargaining agreements with various expiration dates. In addition, employees who are not currently represented by labor unions may seek union representation in the future. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failureIf we are unable to do so mayrenegotiate our collective bargaining agreements when they expire, any work stoppages or other labor disturbances at these facilities could have an adverse effect on our business, impact our ability to make distributions to our unitholders and payments of our debt obligations, and increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage or other adverse employee relations event at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.


The market price of our common stock may fluctuate significantly, and the value of a stockholder’s investment could be impacted.


The market price of our common stock may be influenced by many factors, some of which are beyond our control, including:


•our quarterly or annual earnings or those of other companies in our industry;
•changes in accounting standards, policies, guidance, interpretations or principles;
•general economic, industry global and stock market conditions;
•the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;
•future sales of our common stock;
•announcements by us or our competitors of significant contracts or acquisitions;
•sales of common stock by us, our senior officers or our affiliates; and/or
•the other factors described in these Risk Factors.


In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially reduce our stock price.



Compliance with and changes in tax laws could materially and adversely impact our financial condition, results of operations and cash flows.

We are subject to extensive tax liabilities, including federal and state income taxes and transactional taxes such as excise, sales and use, payroll, franchise, withholding and property taxes. New tax laws and regulations and changes in existing tax laws and regulations could result in increased expenditures by us for tax liabilities in the future and could materially and adversely impact our financial condition, results of operations and cash flows.

Additionally, many tax liabilities are subject to periodic audits by taxing authorities, and such audits could subject us to interest and penalties.


Item 1B. Unresolved Staff Comments


We do not have any unresolved staff comments.




40
Table of Content

Item 3.Legal Proceedings


Commitment and Contingency Reserves


We periodically establish reserves forIn the ordinary course of business, we may become party to legal, regulatory or administrative proceedings or governmental investigations, including environmental and other matters. Damages or penalties may be sought from us in some matters and certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reservesmatters may require years to be adequate, future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

resolve. While the outcome and impact of these proceedings and investigations on us cannot be predicted with certainty, based on advice of counsel and information currently available to us, management believes that the resolution of these proceedings and investigations through settlement or adverse judgment will not either individually or in the aggregate have a materiallymaterial adverse effect on our financial condition, results of operations or cash flows.


Environmental Matters

WeThe environmental proceedings are reporting the following proceedingsreported to comply with SEC regulations which require us to disclose proceedings arising under federal, state, provincial or local provisions regulating the discharge of materials into the environment or protecting the environment ifwhen a governmental authority is party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe that such proceedings may result in monetary sanctions ofcould exceed $300,000 or more.Certain disclosures made under the SEC’s prior $100,000 or more. threshold will remain until their resolution.

Environmental Matters

Our respective subsidiaries have or will develop corrective action plans regarding these disclosures that will be implemented in consultation with the respective federal and state agencies. It is not possible to predict the ultimate outcome of these proceedings, although none are currently expected to have a material effect on our financial condition, results of operations or cash flows.


Cheyenne
HollyFrontier Cheyenne Refining LLC (“HFCR”) has been engaged in discussions with the Wyoming Department of Environmental Quality (“WDEQ”) and the United States Environmental Protection Agency (“EPA”) relating to a Notice of Violation issued in late 2016 for possiblealleged violations of air quality standardsemission limitations and requirements related to operation of certain refinery units at the Cheyenne RefineryRefinery.

Notices of Violations were issued by the WDEQ in late 2016 and 2017.2018. On July 18, 2019, HFCR and the WDEQ are working towardsentered into a consent decree, and on August 9, 2019, HFCR paid penalties in the amount of $117,000 related to alleged violations of air quality limits that occurred during the second quarter of 2016 through the second quarter of 2017. Separately, on October 23, 2019, HFCR received a Notice of Violation from the WDEQ for possible violations of air quality standards during the first and second quarters of 2019. HFCR and WDEQ have been in discussions to resolve WDEQ’s alleged violations of air quality limits that occurred during the third quarter of 2017 through calendar year 2019. The WDEQ and HFCR also previously agreed that the discussions would also include exceedances that occurred during the first quarter of 2020 through the cessation of petroleum refining operations at the Cheyenne Refinery in the third quarter of 2020. During a settlement conference on November 9, 2020, WDEQ proposed a settlement that would impose a penalty of this matter.$95,075 to resolve the alleged violations that occurred during the third quarter of 2017 through the date of the refinery shutdown. As part of the settlement process, on January 15, 2021, the State of Wyoming filed a complaint with the Wyoming District Court addressing the alleged violations. The WDEQ and HFCR agreed on the terms of a consent decree to resolve the alleged violations, and on February 18, 2021, a Joint Motion for Entry of Consent Decree and the Consent Decree were filed with the Wyoming District Court. HFCR expects that the Wyoming District Court will enter the Consent Decree during the first quarter of 2021.


El Dorado
TheHollyFrontier El Dorado Refinery isRefining LLC (“HFEDR”) has been engaged in discussions with, and has responded to document requests from, the EPA, and the U.S. Department of Justice (“DOJ”) and the State of Kansas regarding potentialalleged Clean Air Act civil violations relating to flaring devices and other equipment at the refinery. Topics of the discussions includeincluded: (a) three information requests for activities occurringbeginning in January 1, 2009, through May 31, 2014 and a September 2017 incident, (b) Risk Management Program compliance issues relating to a November 2014 inspection and subsequent events, (c) a Notice of Violation issued by the EPA in August 2017. We will continue to work2017, and (d) possible late reporting under the Emergency Planning and Community Right-to-Know Act for the release of sulfur dioxide and visible emissions from October 2018.

Some of the foregoing civil investigations resulted from fires that occurred at the El Dorado Refinery in September 2017, October 2018 and March 2019. An employee fatality occurred during the September 2017 event. On May 28, 2020, HFEDR reached a settlement in the form of a proposed consent decree with the EPA, the DOJ,and the State of Kansas regarding the alleged Clean Air Act civil violations relating to flaring devices and other equipment at the refinery, as well as compliance with the Clean Air Act’s Risk Management Program (“RMP”).
41
Table of Content

The proposed consent decree was lodged with the U.S. District Court for the District of Kansas, and the 30-day public comment period ended on July 18, 2020. On July 27, 2020, the EPA, the DOJ and the State of Kansas filed their Unopposed Motion to resolve these matters.enter the Consent Decree with the U.S. District Court for the District of Kansas, and on August 27, 2020, the consent decree was entered by the district judge and became effective. Pursuant to the consent decree, among other terms and conditions, HFEDR is required to complete certain projects, implement protocols regarding the examination of its fired heaters and conduct a third party RMP audit of certain of its processes. In addition, HFEDR is required to pay a civil penalty of $2 million to the United States and $2 million to the State of Kansas in two installments, the first half within 30 days of entry of the consent decree and the second within six months of entry of the consent decree. The initial payment of $1 million each was paid to the EPA on September 18, 2020 and the State of Kansas on September 22, 2020, and HFEDR has undertaken several of the required projects. The consent decree resolves the alleged federal and state civil Clean Air Act liability for penalties and injunctive relief, other than potential civil penalties for RMP violations. Finally, as part of the settlement, a 2009 consent decree applicable to the refinery was terminated.


The Occupational Safety and Health Administration (“OSHA”) conducted investigations into both the September 2017 and March 2019 events identified above, and HFEDR settled the OSHA claims related to those investigations in 2018 and 2019, respectively. In April 2019, HFEDR became aware that the EPA also initiated a criminal investigation into one or more of the foregoing events. HFEDR has received a grand jury subpoena requesting certain documents be provided to the EPA with respect to the September 2017 event. We are cooperating with this investigation.

Tulsa
HollyFrontier Tulsa Refining LLC (“HFTR”) manufactures paraffin and hydrocarbon waxes at its Tulsa West facility. On March 11, 2014, the EPA issued a notice to HFTR of possible violations of certain provisions of the federal Toxic Substances Control Act in connection with the manufacture of certain of these products. HFTR and the EPA met and are working productively towards a settlement of this matter.

HFTR operates under two Consent Decrees with the EPA and the Oklahoma Department of Environmental Quality (“ODEQ”). for the East and West Refineries. On April 3, 2019, the EPA notified HFTR of potential violations of the Consent Decrees. On December 13,1, 2020, ODEQ, on behalf of ODEQ and the EPA, issued two demand letters alleging violations under the Consent Decrees, which stemmed from inspections conducted by the EPA at the refineries from May 1 through 5, 2017, duringas well as from a meeting betweenreview of the parties,refineries’ records. The alleged violations included the failure to comply with applicable continuous emissions monitoring system (CEMS) requirements and exceedances of the hydrogen sulfide (H2S) emission limits. During a follow-up conference call with ODEQ, proposedon January 6, 2021, ODEQ shared its stipulated penalties relatedpenalty amounts for alleged violations pursuant to violations of the two Consent Decrees. TheHFTR submitted timely responses to the ODEQ demand letters on February 8, 2021. It is too soon to predict the outcome of this matter.

Woods Cross
HollyFrontier Woods Cross Refining LLC (“HFWCR”) operates under a federal consent decree with the EPA and the Utah Department of Environmental Quality. On November 3, 2020, HFWCR received a letter from the EPA identifying potential violations relateof HFWCR’s federal consent decree that occurred from calendar year 2015 through the date of the letter. HFWCR provided a response letter to the EPA on December 3, 2020 disputing certain of the potential violations in the EPA's November 3, 2020 letter, and HFWCR supplemented its response letter on February 5, 2021 with additional information. It is too soon to predict the outcome of this matter.

Federal Trade Commission

On July 23, 2019, the Federal Trade Commission (“FTC”) issued a Civil Investigative Demand and a related Subpoena Duces Tecum requesting we provide specified information relating to the Sonneborn acquisition that closed on February 1, 2019.

We cooperated with the FTC in its investigation. On December 2, 2020, the FTC notified us that no further action was warranted, and it had closed the investigation.

Renewable Fuel Standard

Various subsidiaries of HollyFrontier are currently intervenors in three lawsuits brought by renewable fuel interest groups against the EPA in federal courts alleging violations of the Renewable Fuel Standard under the Clean Air Act regulated fuel gas and flare operations. HFTR is currently negotiatingchallenging the EPA’s handling of small refinery exemptions. We intervened to vigorously defend the EPA’s position on small refinery exemptions because we believe the EPA correctly applied applicable law to the matters at issue.

On January 24, 2020, in the first of these lawsuits, the U.S. Court of Appeals for the Tenth Circuit vacated the small refinery exemptions granted to two of our refineries for 2016 and remanded the case to the EPA for further proceedings. On April 15, 2020, the Tenth Circuit entered its mandate, remanding the matter back to the EPA. On September 4, 2020, various subsidiaries of HollyFrontier filed a Petition for a Writ of Certiorari with the ODEQU.S. Supreme Court appealing the Tenth Circuit decision. On
42
Table of Content
January 8, 2021, the U.S. Supreme Court granted HollyFrontier’s petition. We anticipate decision from the Supreme Court in June 2021. We expect that we will not know what steps the EPA will take with respect to our 2016 small refinery exemptions or how the case will impact future small refinery exemptions until after the Supreme Court’s decision in this matter.

The second lawsuit is before the Tenth Circuit. The matter is fully briefed and remains pending before that court.

The third lawsuit is before the EPA.DC Circuit. Briefing of the issues before the court commenced on December 7, 2020; however, in light of the Supreme Court’s decision to hear HollyFrontier’s appeal of the Tenth Circuit decision, this case was stayed pending a decision from the Supreme Court.


In December 2020, various subsidiaries of HollyFrontier also filed a petition for review in the DC Circuit challenging EPA’s denial of small refinery exemption petitions for years prior to 2016. The petition was consolidated with petitions from eight other refining companies challenging the same decision. In light of the Supreme Court’s decision to hear HollyFrontier’s appeal of the Tenth Circuit decision, this case was stayed pending a decision from the Supreme Court.

Other


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




Item 4.Mine Safety Disclosures

Item 4.Mine Safety Disclosures

Not Applicable.



43
Table of Content

PART II


Item 5.Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Item 5.Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the New York Stock Exchange under the trading symbol “HFC.” The following table sets forth the range of the daily high and low sales prices per share of common stock, dividends declared per share and the trading volume of common stock for the periods indicated:


Years Ended December 31, High Low Dividends Trading Volume
2017        
Fourth quarter $52.00
 $34.47
 $0.33
 152,263,000
Third quarter $36.46
 $25.97
 $0.33
 180,192,400
Second quarter $29.14
 $23.46
 $0.33
 171,701,200
First quarter $34.78
 $26.23
 $0.33
 188,138,300
         
2016        
Fourth quarter $34.13
 $22.63
 $0.33
 227,228,500
Third quarter $27.98
 $22.07
 $0.33
 263,014,600
Second quarter $37.98
 $22.53
 $0.33
 201,750,800
First quarter $41.29
 $29.00
 $0.33
 197,404,600

In May 2015,November 2019, our Board of Directors approved a $1$1.0 billion share repurchase program, authorizing uswhich replaced all existing share repurchase programs. The timing and amount of stock repurchases will depend on market conditions and corporate, regulatory and other relevant considerations. We do not intend to repurchase common stock inunder our $1.0 billion share repurchase program until commodity prices and demand for products normalize. This program may be discontinued at any time by the open market or through privately negotiated transactions based on market conditions, securities law limitations and other relevant considerations.Board of Directors. The following table includes repurchases made under this program during the fourth quarter of 2017.2020.


PeriodTotal Number of
Shares Purchased		Average Price
Paid Per Share		Total Number of
Shares Purchased
as Part of Publicly Announced Plans or Programs		Maximum Dollar
Value of Shares
that May Yet Be
Purchased under the Plans or Programs
October 2020— $— — $1,000,000,000 
November 2020— $— — $1,000,000,000 
December 2020— $— — $1,000,000,000 
Total for October to December 2020— — 
Period 
Total Number of
Shares Purchased
 
Average Price
Paid Per Share
 
Total Number of
Shares Purchased
as Part of Publicly Announced Plans or Programs
 
Maximum Dollar
Value of Shares
that May Yet Be
Purchased under the Plans or Programs
October 2017 —
 $—
 —
 $178,811,213
November 2017 —
 $—
 —
 $178,811,213
December 2017 —
 $—
 —
 $178,811,213
Total for October to December 2017 —
   —
  



As of February 13, 2018,16, 2021, we had approximately 91,488101,664 stockholders, including beneficial owners holding shares in street name.


We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors.




44
Table of Content

Item 6.Selected Financial Data

Item 6.Selected Financial Data

The following table shows our selected financial information as of the dates or for the periods indicated. This table should be read in conjunction with Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K.


Years Ended December 31,
20202019201820172016
(In thousands, except per share data)
FINANCIAL DATA
For the period
Sales and other revenues$11,183,643 $17,486,578 $17,714,666 $14,251,299 $10,535,700 
Income (loss) before income taxes(747,046)1,171,504 1,524,467 868,863 (171,534)
Income tax expense (benefit)(232,147)299,152 347,243 (12,379)19,411 
Net income (loss)(514,899)872,352 1,177,224 881,242 (190,945)
Less net income attributable to noncontrolling interest86,549 99,964 79,264 75,847 69,508 
Net income (loss) attributable to HollyFrontier stockholders$(601,448)$772,388 $1,097,960 $805,395 $(260,453)
Earnings (loss) per share - basic$(3.72)$4.64 $6.25 $4.54 $(1.48)
Earnings (loss) per share - diluted$(3.72)$4.61 $6.19 $4.52 $(1.48)
Cash dividends declared per common share$1.40 $1.34 $1.32 $1.32 $1.32 
Average number of common shares outstanding:
Basic161,983 166,287 175,009 176,174 176,101 
Diluted161,983 167,385 176,661 177,196 176,101 
Net cash provided by operating activities$457,931 $1,548,611 $1,554,416 $951,390 $606,948 
Net cash used for investing activities$(330,162)$(972,914)$(360,520)$(959,670)$(801,597)
Net cash provided by (used for) financing activities$353,226 $(848,255)$(664,328)$(72,630)$838,695 
At end of period
Cash, cash equivalents and investments in marketable securities$1,368,318 $885,162 $1,154,752 $630,757 $1,134,727 
Working capital$1,935,605 $1,620,261 $2,128,224 $1,640,118 $1,767,780 
Total assets$11,506,864 $12,164,841 $10,994,601 $10,692,154 $9,435,661 
Total debt$3,142,718 $2,455,640 $2,411,540 $2,498,993 $2,235,137 
Total equity$5,722,203 $6,509,426 $6,459,059 $5,896,940 $5,301,985 



45
 Years Ended December 31,
 2017 2016 2015 2014 2013
 (In thousands, except per share data)
FINANCIAL DATA         
For the period         
Sales and other revenues$14,251,299
 $10,535,700
 $13,237,920
 $19,764,327
 $20,160,560
Income (loss) before income taxes (1,2)
868,863
 (171,534) 1,208,568
 467,500
 1,159,399
Income tax expense (benefit)(12,379) 19,411
 406,060
 141,172
 391,576
Net income (loss)881,242
 (190,945) 802,508
 326,328
 767,823
Less net income attributable to noncontrolling interest75,847
 69,508
 62,407
 45,036
 31,981
Net income (loss) attributable to HollyFrontier stockholders$805,395
 $(260,453) $740,101
 $281,292
 $735,842
Earnings (loss) per share attributable to HollyFrontier stockholders - basic$4.54
 $(1.48) $3.91
 $1.42
 $3.66
Earnings (loss) per share attributable to HollyFrontier stockholders - diluted$4.52
 $(1.48) $3.90
 $1.42
 $3.64
Cash dividends declared per common share$1.32
 $1.32
 $1.31
 $3.26
 $3.20
Average number of common shares outstanding:         
Basic176,174
 176,101
 188,731
 197,243
 200,419
Diluted177,196
 176,101
 188,940
 197,428
 201,234
          
Net cash provided by operating activities$951,390
 $606,948
 $985,868
 $758,596
 $869,174
Net cash used for investing activities$(959,670) $(801,597) $(381,748) $(292,322) $(526,735)
Net cash provided by (used for) financing activities$(72,630) $838,695
 $(1,105,572) $(838,392) $(1,160,035)
          
At end of period         
Cash, cash equivalents and investments in marketable securities$630,757
 $1,134,727
 $210,552
 $1,042,095
 $1,665,263
Working capital$1,640,118
 $1,767,780
 $587,450
 $1,549,004
 $2,445,953
Total assets$10,692,154
 $9,435,661
 $8,388,299
 $9,230,047
 $10,055,763
Total debt$2,498,993
 $2,235,137
 $1,040,040
 $1,054,297
 $996,543
Total equity$5,896,940
 $5,301,985
 $5,809,773
 $6,100,719
 $6,609,398


(1)Reflects non-cash lower of cost or market inventory valuation adjustments that increased pre-tax earnings by $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016 and decreased pre-tax earnings by $227.0 million and $397.5 million for the years ended December 31, 2015 and 2014, respectively.

(2)Includes a long-lived asset impairment charge of $19.2 million that relate to our Woods Cross Refinery for the year ended December 31, 2017 and goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million, respectively, that relate to our Cheyenne Refinery, for the year ended December 31, 2016.



Table of Content

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 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include HEP and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.




OverviewOVERVIEW


We are principally an independent petroleum refiner and marketer that produces high-value refinedlight products such as gasoline, diesel fuel, jet fuel, specialty lubricant products and specialty and modified asphalt. We own and operate refineries havinglocated in Kansas, Oklahoma, New Mexico and Utah and market our refined products principally in the Southwest United States, the Rocky Mountains extending into the Pacific Northwest and in other neighboring Plains states. In addition, we produce base oils and other specialized lubricants in the United States, Canada and the Netherlands, and export products to more than 80 countries. We also own a combined nameplate57% limited partner interest and a non-economic general partner interest in HEP, a master limited partnership that provides petroleum product and crude oil processing capacitytransportation, terminalling, storage and throughput services to the petroleum industry, including HollyFrontier Corporation subsidiaries.

In the third quarter of 457,000 barrels per day2020, we permanently ceased petroleum refining operations at our Cheyenne Refinery and subsequently began converting certain assets at our Cheyenne Refinery to renewable diesel production. This decision was primarily based on a positive outlook in the market for renewable diesel and the expectation that serve markets throughoutfuture free cash flow generation at our Cheyenne Refinery would be challenged due to lower gross margins resulting from the Mid-Continent, Southwest and Rocky Mountain regionseconomic impact of the United States. Our refineriesCOVID-19 pandemic and compressed crude differentials due to dislocations in the crude oil market. Additional factors included uncompetitive operating and maintenance costs forecasted for our Cheyenne Refinery and the anticipated loss of the EPA’s small refinery exemption. The renewable diesel units are locatedexpected to be completed in El Dorado, Kansas (the El Dorado Refinery), Tulsa, Oklahoma (the Tulsa Refineries),the first quarter of 2022 with an expected capital budget between $125-$175 million.

During the second quarter of 2020, we recorded long-lived asset impairment charges of $232.2 million related to our Cheyenne Refinery asset group. In connection with the cessation of petroleum refining operations at our Cheyenne Refinery, we recognized $24.7 million in decommissioning expense for the year ended December 31, 2020. In addition, for the year ended December 31, 2020, we recorded a reserve of $9.0 million against our repair and maintenance supplies inventory and $3.8 million in employee severance costs related to the conversion of our Cheyenne Refinery to renewable diesel production. These decommissioning, inventory reserve and severance costs were recognized in operating expenses, of which comprise two production facilities,$24.8 million was recorded in our Refining segment and $12.7 million was recorded in our Corporate and Other segment.

During the Tulsa Westsecond quarter of 2020, we also initiated and East facilities, Artesia, New Mexico,completed a corporate restructuring, which operatesis expected to save approximately $30 million per year of ongoing cash expenses. As a result of this restructuring, we recorded $3.7 million in conjunction with crude, vacuum distillationemployee severance costs, which were recognized primarily as operating expenses in our Refining segment and other facilities situated 65 miles awayselling, general and administrative expenses in Lovington, New Mexico (collectively,our Corporate and Other segment.

During the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery)first quarter of 2021, we initiated a restructuring within our Lubricants and Woods Cross, Utah (the Woods Cross Refinery).Specialty Products segment, which is expected to save approximately $15 million per year of ongoing cash expenses. Over the next twelve months, we anticipate pre-tax costs of $8 -$10 million for severance obligations.


On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc.,November 12, 2018, we entered into a sharean equity purchase agreement with Suncor to acquire 100% of the issued and outstanding capital stock of PCLI.Sonneborn. The acquisition closed on February 1, 2017.2019. Cash consideration paid was $862.1 million, or $1.125 billion in Canadian dollars.

PCLI$662.7 million. Sonneborn is a Canadian-based producer of base oils with a plant having 15,600 BPD of lubricant production capacity that is located in Mississauga, Ontario. The facility is downstream integrated from base oils to finished lubricants and produces a broad spectrum of specialty lubricants andhydrocarbon chemicals such as white oils, that are distributed to end customers worldwide through a global sales networkpetrolatums and waxes with locationsmanufacturing facilities in Canada, the United States Europe and China.Europe.


On July 10, 2018, we entered into a definitive agreement to acquire Red Giant Oil, a privately-owned lubricants company. The acquisition closed on August 1, 2018. Cash consideration paid was $54.2 million. Red Giant Oil is one of the largest suppliers of locomotive engine oil in North America and is headquartered in Council Bluffs, Iowa with storage and distribution facilities in Iowa and Wyoming, along with a blending and packaging facility in Texas.

46
Table of Content
For the year ended December 31, 2017,2020, net incomeloss attributable to HollyFrontier stockholders was $805.4$(601.4) million compared to a net lossincome of $260.5$772.4 million and net income $740.1$1,098.0 million for the years ended December 31, 2016,2019, and 2015,2018, respectively. Overall gross refining margins per produced barrel sold for 2017 increased 42%2020 decreased 54% over the year ended December 31, 2016, which was2019 due principally to higherlower crack spreads throughout 2017.and crude oil basis differentials. Included in our financial results for the current year was aended December 31, 2020 were non-cash items consisting of goodwill and long-lived asset impairment charge, offset by an inventory reserve adjustment.charges.


Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS regulations, which increased the volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as RINs, in lieu of such blending. Compliance with RFS regulations significantly increases our cost of products sold, with RINs costs totaling $288.4$148.5 million for the year ended December 31, 2017,2020.

Impact of COVID-19 on Our Business
The COVID-19 pandemic caused a decline in U.S. and global economic activity starting in the first quarter of 2020. This decrease reduced both volumes and unit margins across our businesses, resulting in lower gross margins and earnings. Following a rebound in the late second and third quarters, demand for transportation fuels continued to be weak compared to 2019. In response to this level of demand, during the fourth quarter of 2020, we operated our Refining segment refineries at an average crude charge of 379,910 BPD.

In our Lubricants and Specialty Products segment, the Rack Forward portion saw improvement in industrial and transportation-related end markets, which is netdrove higher demand and unit margins during the second half of 2020. Within the Rack Back portion, demand for base oils increased to 2019 levels while supply was limited due to a number of factors, which drove higher margins and utilization at our facilities in the third quarter.

The stabilization of demand drove a broad increase in commodity prices, resulting in values for our inventories held at December 31, 2020 above the costs of these inventories using the last-in, first-out (“LIFO”) method and in a lower of cost or market valuation gain of $149.2 million for the three months ended December 31, 2020. We also drew down on our inventory levels to better manage working capital in the fourth quarter of 2020, which resulted in a $35 million increase in cost of products sold for the quarter.

Our standalone (excluding HEP) liquidity was approximately $2,696.3 million at December 31, 2020, consisting of cash and cash equivalents of $1,346.3 million and an undrawn $1.35 billion credit facility maturing in 2022. Our standalone (excluding HEP) long-term debt was $1.75 billion as of December 31, 2020, which consists of $350.0 million in 2.625% senior notes due in 2023, $1.0 billion of 5.875% senior notes due in 2026 and $400.0 million in 4.500% senior notes due in 2030.


OUTLOOK

The impact of the $57.7 million costCOVID-19 pandemic on the global macroeconomy created an unprecedented reduction resulting from reinstatement of 2016 RINs as described in Note 8 “Inventories”demand in the Notesfirst half of 2020, as well as a lack of forward visibility, for many of the transportation fuels, lubricants and specialty products and the associated transportation and terminal services we provide. We have seen improvement in demand for these products and services since the initial wave of COVID-19 infections during the second quarter of 2020, and with the increasing availability of vaccines, we believe there is a path to Consolidated Financial Statements.a fulsome recovery in demand in 2021.



OUTLOOK

The profitabilityIn response to the COVID-19 pandemic, and with the health and safety of our refining business is largely drivenemployees as a top priority, we continue a range of initiatives, including limiting onsite staff at all of our facilities, implementing a work-from-home policy for certain employees and restricting travel unless approved by senior leadership. We will continue to monitor COVID-19 developments and the dynamic environment to properly address these policies going forward.

Within our operational reliability and crack spreads (the price difference between refined products and inputs such as crude oil), which are driven byRefining segment, for the supply and demandfirst quarter of refined product markets. In 2017, crack spreads showed material improvement over 2016 as global and North American refined product market supply and demand tightened. Going into 2018, we are anticipating continued demand growth for refined products and are optimistic about margins. Additionally,2021, we expect to benefitrun between 350,000-380,000 barrels per day of crude oil. In addition to continued weakness in demand resulting from wideningthe COVID-19 pandemic, the crude differentials on some of our key inputscharge in the Refining segment: Cushing-based crude oilsfirst quarter of 2021 has also been adversely impacted by scheduled maintenance at our Tulsa West and Canadian heavy crude oils.

Our lubricants business is driven by secular demand for higher quality lubricants and greases, cyclical macroeconomic factors and our own operational reliability. In 2017, we acquired and integrated the Petro-Canada Lubricants business into our business and going into 2018, we anticipate strong earnings growth based on continued economic growthWoods Cross refineries as well as reduced availability, and an increase in the executionprice, of natural gas due to the recent extreme cold weather throughout the Mid-Continent and Southwest. We expect to adjust refinery production levels commensurate with market demand.

Within our organic growth strategy.Lubricants and Specialty Products segment, we expect a normal seasonal rebound in the first quarter of 2021. However, we do not have enough visibility to issue forward guidance at this time. Similar to our Refining segment, we expect to adjust production levels commensurate with market demand.


47
Table of Content

At HEP, we expect to see demand for transportation and terminal services grow with underlying demand for transportation fuels and crude oil. In 2021, HEP expects to hold the quarterly distribution constant at $0.35 per unit, or $1.40 on an annualized basis. HEP remains committed to its distribution strategy focused on funding all capital expenditures and distributions within free cash flow and maintaining distributable cash flow coverage of 1.3x or greater with the goal of reducing leverage to 3.0-3.5x.
HEP’s
During the third quarter of 2020, we increased our liquidity by $750.0 million with the issuance of $350.0 million in 2.625% senior notes due in 2023 and $400.0 million in 4.500% senior notes due in 2030. This additional liquidity may be used for general corporate purposes and is expected to support the planned growth of our renewables business is largely drivenand the unexpected economic impact of COVID-19, as needed. We do not intend to repurchase common stock under our $1.0 billion share repurchase program until demand for our products normalize.

On March 27, 2020, the U.S. government passed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), an approximately $2 trillion stimulus package that includes various provisions intended to provide relief to individuals and businesses in the form of tax changes, loans and grants, among others. At this time, we have not sought relief in the form of loans or grants from the CARES Act; however, we have benefited from certain tax deferrals in the CARES Act and may benefit from other tax provisions if we meet the requirements to do so. We anticipate $50.0 million to $60.0 million in cash tax benefit in 2021 from the loss carryback potential under the CARES Act. As a result of the net operating loss incurred in the year ended December 31, 2020, we will also file refund claims of approximately $21.0 million to recover estimated tax payments made during the year.

The extent to which our future results are affected by the operational reliabilityCOVID-19 pandemic will depend on various factors and consequences beyond our control, such as the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic and the speed and effectiveness of responses to combat the virus. The COVID-19 pandemic, and the volatile regional and global economic conditions stemming from it, could also exacerbate the risk factors identified in this Form 10-K under “Risk Factors” in Item 1A. The COVID-19 pandemic may also materially adversely affect our refineries and contractual tariff increases. Based on our volume forecasts,results in a manner that is either not currently known or that we expect HEPdo not currently consider to be ablea significant risk to grow its limited partner distribution approximately 4% with a distribution coverage ratio of roughly 1.0x.our business.


A more detailed discussion of our financial and operating results for the years ended December 31, 2017, 20162020 and 20152019 is presented in the following sections. Discussions of year-over-year comparisons for 2019 and 2018 can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019.




48
Results Of Operations

Financial Data
  Years Ended December 31,
  2017 2016 2015
  (In thousands, except per share data)
Sales and other revenues $14,251,299
 $10,535,700
 $13,237,920
Operating costs and expenses:      
Cost of products sold (exclusive of depreciation and amortization):      
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment) 11,467,799
 8,765,927
 10,239,218
Lower of cost or market inventory valuation adjustment (108,685) (291,938) 226,979
  11,359,114
 8,473,989
 10,466,197
Operating expenses (exclusive of depreciation and amortization) 1,294,234
 1,018,839
 1,060,373
Selling, general and administrative expenses (exclusive of depreciation and amortization) 264,874
 125,648
 120,846
Depreciation and amortization 409,937
 363,027
 346,151
Goodwill and asset impairment 19,247
 654,084
 —
Total operating costs and expenses 13,347,406
 10,635,587
 11,993,567
Income (loss) from operations 903,893
 (99,887) 1,244,353
Other income (expense):      
Earnings (loss) of equity method investments 12,510
 14,213
 (3,738)
Interest income 3,736
 2,491
 3,391
Interest expense (117,597) (72,192) (43,470)
Loss on early extinguishment of debt (12,225) (8,718) (1,370)
Gain (loss) on foreign currency swap 24,545
 (6,520) —
Gain on foreign currency transactions 16,921
 —
 —
Remeasurement gain on HEP pipeline interest acquisitions 36,254
 —
 —
Other, net 826
 (921) 9,402
  (35,030) (71,647) (35,785)
Income (loss) before income taxes 868,863
 (171,534) 1,208,568
Income tax expense (benefit) (12,379) 19,411
 406,060
Net income (loss) 881,242
 (190,945) 802,508
Less net income attributable to noncontrolling interest 75,847
 69,508
 62,407
Net income (loss) attributable to HollyFrontier stockholders $805,395
 $(260,453) $740,101
Earnings (loss) per share attributable to HollyFrontier stockholders:      
Basic $4.54
 $(1.48) $3.91
Diluted $4.52
 $(1.48) $3.90
Cash dividends declared per common share $1.32
 $1.32
 $1.31
Average number of common shares outstanding:      
Basic 176,174
 176,101
 188,731
Diluted 177,196
 176,101
 188,940

Table of Content

RESULTS OF OPERATIONS

Financial Data
Years Ended December 31,
202020192018
(In thousands, except per share data)
Sales and other revenues$11,183,643 $17,486,578 $17,714,666 
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization):
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment)9,158,805 13,918,384 13,940,782 
Lower of cost or market inventory valuation adjustment78,499 (119,775)136,305 
9,237,304 13,798,609 14,077,087 
Operating expenses (exclusive of depreciation and amortization)1,300,277 1,394,052 1,285,838 
Selling, general and administrative expenses (exclusive of depreciation and amortization)313,600 354,236 290,424 
Depreciation and amortization520,912 509,925 437,324 
Goodwill and long-lived asset impairments545,293 152,712 — 
Total operating costs and expenses11,917,386 16,209,534 16,090,673 
Income (loss) from operations(733,743)1,277,044 1,623,993 
Other income (expense):
Earnings of equity method investments6,647 5,180 5,825 
Interest income7,633 22,139 16,892 
Interest expense(126,527)(143,321)(131,363)
Gain on business interruption insurance settlement81,000 — — 
Gain on sales-type leases33,834 — — 
Loss on early extinguishment of debt(25,915)— — 
Gain on foreign currency transactions2,201 5,449 6,197 
Other, net7,824 5,013 2,923 
(13,303)(105,540)(99,526)
Income (loss) before income taxes(747,046)1,171,504 1,524,467 
Income tax expense (benefit)(232,147)299,152 347,243 
Net income (loss)(514,899)872,352 1,177,224 
Less net income attributable to noncontrolling interest86,549 99,964 79,264 
Net income (loss) attributable to HollyFrontier stockholders$(601,448)$772,388 $1,097,960 
Earnings (loss) per share:
Basic$(3.72)$4.64 $6.25 
Diluted$(3.72)$4.61 $6.19 
Cash dividends declared per common share$1.40 $1.34 $1.32 
Average number of common shares outstanding:
Basic161,983 166,287 175,009 
Diluted161,983 167,385 176,661 

Other Financial Data
Years Ended December 31,
 202020192018
 (In thousands)
Net cash provided by operating activities$457,931 $1,548,611 $1,554,416 
Net cash used for investing activities$(330,162)$(972,914)$(360,520)
Net cash provided by (used for) financing activities$353,226 $(848,255)$(664,328)
Capital expenditures$330,160 $293,763 $311,029 
EBITDA (1)
$(193,789)$1,702,647 $1,996,998 

49
Table of Content
  Years Ended December 31,
  2017 2016 2015
  (In thousands)
Net cash provided by operating activities $951,390
 $606,948
 $985,868
Net cash used for investing activities $(959,670) $(801,597) $(381,748)
Net cash provided by (used for) financing activities $(72,630) $838,695
 $(1,105,572)
Capital expenditures $272,259
 $479,790
 $676,155
EBITDA (1)
 $1,329,039
 $200,404
 $1,533,761
(1)Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income (loss) attributable to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under 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 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 financial covenants. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

(1)Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income (loss) attributable to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under 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 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 financial covenants. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


Supplemental Segment Operating Data
Effective in the fourth quarter of 2017, we revised our reportable segments to align with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, our Tulsa Refineries lubricants operations, previously reported in the Refining segment, are now combined with the operations of our Petro-Canada Lubricants business and reported in the Lubricants and Specialty Products segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation.

Our operations are organized into three reportable segments, Refining, Lubricants and Specialty Products and HEP. See Note 20 “Segment Information” in the Notes to Consolidated Financial Statements for additional information on our reportable segments.


Refining Segment Operating Data


Our refinery operations include the El Dorado, Tulsa, Navajo Cheyenne and Woods Cross Refineries. The following tables set forth information, including non-GAAP performance measures, about our consolidated refinery operations.operations, which has been retrospectively adjusted to reflect the revised regional groupings upon the Cheyenne Refinery permanently ceasing petroleum refining operations in the third quarter of 2020. The cost of products and refinery gross and net operating margins do not include the non-cash effects of goodwill andlong-lived asset impairmentsimpairment charges, lower of cost or market inventory valuation adjustments and depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

Years Ended December 31,
202020192018
Consolidated
Crude charge (BPD) (1)
365,190 388,860 384,380 
Refinery throughput (BPD) (2)
395,080 417,570 413,780 
Sales of produced refined products (BPD) (3)
391,670 414,370 408,390 
Refinery utilization (4)
90.2 %96.0 %94.9 %
Average per produced barrel (5)
Refinery gross margin$7.29 $15.92 $16.50 
Refinery operating expenses (6)
6.05 6.12 6.06 
Net operating margin$1.24 $9.80 $10.44 
Refinery operating expenses per throughput barrel (7)
$6.00 $6.07 $5.98 
During
(1)Crude charge represents the fourth quarterbarrels per day of 2017, we revisedcrude oil processed at our refineries.
(2)Refinery throughput represents the following refining segment operating data computations:barrels per day of crude and other refinery gross margin; net operating margin;feedstocks input to the crude units and operating expenses to better align with similar measurements provided by other companies inconversion units at our industryrefineries.
(3)Represents barrels sold of refined products produced at our refineries (including HFC Asphalt) and to facilitate comparisondoes not include volumes of our refining performance relative to our peers. Effective with this change, these measurements are now inclusive of all refining segment activities including HFC asphalt operations and revenues and costs related torefined products purchased for resale andor volumes of excess crude oil sales. All prior period data has been retrospectively adjustedsold.
(4)Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity is 405,000 BPSD.
(5)Represents average amount per produced barrel sold, which is a non-GAAP measure. Reconciliations to reflectamounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
(6)Represents total Mid-Continent and West regions operating expenses, exclusive of long-lived asset impairment charges and depreciation and amortization, divided by sales volumes of refined products produced at our current presentation.refineries.
(7)Represents total Mid-Continent and West regions operating expenses, exclusive of long-lived asset impairment charges and depreciation and amortization, divided by refinery throughput.

50
Table of Content

  Years Ended December 31,
  2017 2016 2015
Consolidated      
Crude charge (BPD) (1)
 438,800
 423,910
 432,560
Refinery throughput (BPD) (2)
 472,010
 457,480
 463,580
Sales of produced refined products (BPD) (3)
 452,270
 440,640
 442,650
Refinery utilization (4)
 96.0% 92.8% 97.6%
       
Average per produced barrel sold (5)
      
Refinery gross margin (6)
 $11.56
 $8.16
 $15.88
Refinery operating expenses (7)
 6.10
 5.64
 5.82
Net operating margin $5.46
 $2.52
 $10.06
       
Refinery operating expenses per throughput barrel (8)
 $5.84
 $5.43
 $5.56

(1)Crude charge represents the barrels per day of crude oil processed at our refineries.
(2)Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.
(3)Represents barrels sold of refined products produced at our refineries (including HFC Asphalt) and does not include volumes of refined products purchased for resale or volumes of excess crude oil sold.
(4)Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2016, our consolidated crude capacity increased from 443,000 BPSD to 457,000 BPSD upon completion of our Woods Cross Refinery expansion project.
(5)Represents average amount per produced barrel sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
(6)Excludes lower of cost or market inventory valuation adjustments that increased refinery gross margin by $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016, respectively, and decreased refinery gross margin by $227.0 million for the year ended December 31, 2015.
(7)Represents total refining segment operating expenses, exclusive of depreciation and amortization, divided by sales volumes of refined products produced at our refineries.
(8)Represents total refining segment operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.

Lubricants and Specialty Products Segment Operating Data


The following table sets forth information about our lubricants and specialty products operations and includes our Petro-Canada Lubricants businessRed Giant Oil for the period FebruaryAugust 1, 20172018 (date of acquisition) through December 31, 2017.2020, and Sonneborn for the period February 1, 2019 (date of acquisition) through December 31, 2020.
Years Ended December 31,
202020192018
Lubricants and Specialty Products
Throughput (BPD)19,645 20,251 19,590 
Sales of produced barrels sold (BPD)32,902 34,827 30,510 
  Years Ended December 31,
Lubricants and Specialty Products 2017 2016 2015
Throughput (BPD) 21,710
 —
 —
Barrels sold (BPD) 31,480
 12,030
 11,140


OurSupplemental financial data attributable to our Lubricants and Specialty Products segment includesis presented below:
Rack Back (1)
Rack Forward (2)
Eliminations (3)
Total Lubricants and Specialty Products
(In thousands)
Year Ended December 31, 2020
Sales and other revenues$505,424 $1,667,809 $(370,023)$1,803,210 
Cost of products sold456,194 1,185,116 (370,023)1,271,287 
Operating expenses96,463 119,605 — 216,068 
Selling, general and administrative expenses22,276 135,540 — 157,816 
Depreciation and amortization29,071 51,585 — 80,656 
Goodwill and long-lived asset impairments (4)
167,017 119,558 — 286,575 
Income (loss) from operations$(265,597)$56,405 $— $(209,192)
Year Ended December 31, 2019
Sales and other revenues$661,523 $1,883,920 $(452,915)$2,092,528 
Cost of products sold620,660 1,412,291 (452,915)1,580,036 
Operating expenses116,984 114,539 — 231,523 
Selling, general and administrative expenses31,854 136,741 — 168,595 
Depreciation and amortization37,001 51,780 — 88,781 
Goodwill impairment (5)
152,712 — — 152,712 
Income (loss) from operations$(297,688)$168,569 $— $(129,119)
Year Ended December 31, 2018
Sales and other revenues$682,892 $1,650,056 $(520,245)$1,812,703 
Cost of products sold633,459 1,268,326 (520,245)1,381,540 
Operating expenses111,155 56,665 — 167,820 
Selling, general and administrative expenses32,086 111,664 — 143,750 
Depreciation and amortization26,955 16,300 — 43,255 
Income (loss) from operations$(120,763)$197,101 $— $76,338 

(1)Rack back consists of our PCLI base oil production activities, by-product sales to third parties and intra-segment base oil sales to rack forward.
(2)Rack forward referred to as “rack back.” “Rack forward” includesactivities include the purchase of base oils from rack back and the blending, packaging, marketing and distribution and sales of finished lubricants and specialty products to third parties. Supplemental financial data attributable
(3)Intra-segment sales of rack back produced base oils to ourrack forward are eliminated under the “Eliminations” column.
(4)During the year ended December 31, 2020, a goodwill impairment charge of $81.9 million was recorded in rack forward. Also, during the year ended December 31, 2020, a long-lived asset impairment charge of $204.7 million was recorded of which $167.0 million was in rack back and $37.7 million was in rack forward.
(5)During the year ended December 31, 2019, a goodwill impairment charge of $152.7 million was recorded in the PCLI reporting unit within the Lubricants and Specialty Products segment is presented below:segment. We separately allocated this charge for purposes of management’s discussion and analysis presentation of rack back and rack forward results entirely to rack back.




51
Table of Content

  
Rack Back (1)
 
Rack Forward (2)
 
Eliminations (3)
 Total Lubricants and Specialty Products
  (In thousands)
Year Ended December 31, 2017        
Sales and other revenues $621,153
 $1,415,842
 $(442,959) $1,594,036
Cost of products sold 504,782
 1,032,161
 (442,959) 1,093,984
Operating expenses 95,303
 127,158
 —
 222,461
Selling, general and administrative expenses 27,618
 77,494
 —
 105,112
Depreciation and amortization 23,471
 8,423
 —
 31,894
Income (loss) from operations $(30,021) $171,812
 $—
 $141,791
         
Year Ended December 31, 2016        
Sales and other revenues $—
 $464,359
 $—
 $464,359
Cost of products sold —
 377,136
 —
 377,136
Operating expenses —
 13,867
 —
 13,867
Selling, general and administrative expenses —
 2,899
 —
 2,899
Depreciation and amortization —
 620
 —
 620
Income from operations $—
 $73,927
 $—
 $73,927
         
Year Ended December 31, 2015        
Sales and other revenues $—
 $493,282
 $—
 $493,282
Cost of products sold —
 415,796
 —
 415,796
Operating expenses —
 14,042
 —
 14,042
Selling, general and administrative expenses —
 2,615
 —
 2,615
Depreciation and amortization —
 254
 —
 254
Income from operations $—
 $60,575
 $—
 $60,575

(1)Rack back consists of our PCLI base oil production activities, by-product sales to third parties and intra-segment base oil sales to rack forward.
(2)Rack forward activities include the purchase of base oils from rack back and the blending, packaging, marketing and distribution and sales of finished lubricants and specialty products to third parties.
(3)Intra-segment sales of rack back produced base oils to rack forward are eliminated under the “Eliminations” column.



Results of Operations –- Year Ended December 31, 20172020 Compared to Year Ended December 31, 20162019


Summary
Net incomeloss attributable to HollyFrontier stockholders for the year ended December 31, 20172020 was $805.4$(601.4) million ($4.54(3.72) per basic and $4.52 per diluted share), a $1,065.8$1,373.8 million increasedecrease compared to a net loss attributable to HollyFrontier stockholdersincome of $260.5$772.4 million ($1.484.64 per basic and $4.61 per diluted share) for the year ended December 31, 2016.2019. Net income increaseddecreased due principally to long-lived asset and goodwill impairment charges of $545.3 million offset by an increase in refining segment sales volumes and$81.0 million gain recognized upon the settlement of a business interruption insurance claim. In addition, net income decreased as a result of lower gross refining margins and the inclusion of earnings attributable to the operations of our recently acquired Petro-Canada Lubricants business. Additionally, we recorded long-lived asset impairment charges totaling $23.2 million for the year ended December 31, 2017 compared to goodwill and long-lived asset impairment charges totaling $654.1 million for the year ended December 31, 2016.lower refining segment sales volumes. For the year ended December 31, 2017,2020, lower of cost or market inventory reserve adjustments increaseddecreased pre-tax earnings by $108.7$78.5 million compared to $291.9an increase of $119.8 million for the year ended December 31, 2016.2019. Refinery gross margins for the year ended December 31, 2017 increased2020 decreased to $11.56$7.29 per produced barrel sold from $8.16$15.92 for the year ended December 31, 2016. During 2017, our Cheyenne Refinery2019. The year ended December 31, 2019 included a goodwill impairment charge of $152.7 million.

Sales and Woods Cross Refinery were each granted a one-year small refinery exemptionOther Revenues
Sales and other revenues decreased 36% from the EPA at which time we recorded a $30.5 million and $27.3 million, respectively, decrease to our cost of products sold, reflecting the reinstatement of RINs previously expensed in 2016. The Tax Cut and Jobs Act was enacted on December 22, 2017, resulting in a tax benefit of $307.1$17,486.6 million for the year ended December 31, 2017.

Table of Content

Sales and Other Revenues
Sales and other revenues increased 35% from $10,535.72019 to $11,183.6 million for the year ended December 31, 2016 to $14,251.3 million for the year ended December 31, 20172020 due to a year-over-year increasedecrease in sales prices and higherlower refined product sales volumes. Sales and other revenues for the years ended December 31, 20172020 and 20162019 include $77.2$98.0 million and $68.9$121.0 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties. Additionally, the operations of our Petro-Canada Lubricants business contributed $1,125.3 million in sales and other revenues included $1,792.7 million and $2,081.2 million in unaffiliated revenues related to our Lubricants and Specialty Products segment for the yearyears ended December 31, 2017.2020 and 2019, respectively.


Cost of Products Sold
Total cost of products sold increased 34%decreased 33% from $8,474.0$13,798.6 million for the year ended December 31, 20162019 to $11,359.1$9,237.3 million for the year ended December 31, 2017,2020, due principally to higherlower crude oil costs and higherlower refined product sales volumesvolumes. Additionally, for the year ended December 31, 2020, we recognized a $78.5 million lower of products. Additionally, cost of products sold reflects a $108.7 million benefit that is attributableor market inventory valuation charge compared to a decreasebenefit of $119.8 million for the same period of 2019, resulting in thea new $318.9 million inventory reserve at December 31, 2020. The lower of cost or market reserve for the year ended December 31, 2017, a $183.3 million decrease compared to $291.9 million for the same period of last year. The reserve at December 31, 20172020 is based on market conditions and prices at that time. Additionally,During the year ended December 31, 2019, we recorded a $30.5 million and $27.3$36.6 million RINs cost reduction during 2017 as a result of the reinstatement of previously utilized RINs following our Cheyenne Refinery and Woods Cross Refinery small refinery exemptions, respectively.exemptions. Also, during the year ended December 31, 2019, we recorded an $18.0 million reduction to cost of products sold as a result of U.S. blender's tax credit legislation that was signed in December 2019 and applied retroactively for the years 2019 and 2018.


Gross Refinery Margins
Gross refinery margin per barrel sold increased 42%decreased 54% from $8.16$15.92 for the year ended December 31, 20162019 to $11.56$7.29 for the year ended December 31, 2017.2020. This was due to the effects of an increasea decrease in the average per barrel sold sales price during the current year period, partially offset by increaseddecreased crude oil and feedstock prices during the current year.prices. Gross refinery margin per barrel does not include the non-cash effects of lower of cost or market inventory valuation adjustments, goodwill andlong-lived asset impairment charges or depreciation and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of sale prices of products sold and cost of products purchased.

Operating Expenses
Operating expenses, exclusive of depreciation and amortization, increased 27% from $1,018.8 million for the year ended December 31, 2016 to $1,294.2 million for the year ended December 31, 2017 due principally to $208.7 million in costs attributable to the operations of our Petro-Canada Lubricants business and higher purchased fuel costs compared to 2016. For the years ended December 31, 2017 and 2016, operating expenses include $137.6 million and $90.4 million, respectively, in costs attributable to HEP operations.

Selling, General and Administrative Expenses
Selling, general and administrative expenses increased 111% from $125.6 million for the year ended December 31, 2016 to $264.9 million for the year ended December 31, 2017, due principally to $127.7 million in costs attributable to the operations of our Petro-Canada Lubricants business and related acquisition and integration costs. Incremental direct acquisition and integration costs of our Petro-Canada Lubricants business totaled $27.9 million and $13.4 million for the years ended December 31, 2017 and 2016, respectively. For the years ended December 31, 2017 and 2016, selling, general and administrative expenses include $11.9 million and $10.1 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses
Depreciation and amortization increased 13% from $363.0 million for the year ended December 31, 2016 to $409.9 million for the year ended December 31, 2017. This increase was due principally to $30.9 million in depreciation and amortization expenses attributable to the operations of our Petro-Canada Lubricants business and capitalized improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2017 and 2016, depreciation and amortization expenses include $77.7 million and $68.8 million, respectively, in costs attributable to HEP operations.

Goodwill and Asset Impairment
During the year ended December 31, 2017, we recorded a $19.2 million long-lived asset impairment charge resulting from management's plan to cease further expansion of our Woods Cross Refinery to add lubricants production compared to goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million, respectively, for the year ended December 31, 2016 that related to our Cheyenne Refinery. See Note 10 “Goodwill” in the Notes to Consolidated Financial Statements for additional information on these impairments.

Interest Income
Interest income for the year ended December 31, 2017 was $3.7 million compared to $2.5 million for the year ended December 31, 2016. This increase was due to higher interest rates received on cash balances during 2017.

Table of Content

Interest Expense
Interest expense was $117.6 million for the year ended December 31, 2017 compared to $72.2 million for the year ended December 31, 2016. This increase was due to interest attributable to higher debt levels during the current year relative to 2016. For the years ended December 31, 2017 and 2016, interest expense included $58.4 million and $52.6 million, respectively, in interest costs attributable to HEP operations.

Loss on Early Extinguishment of Debt
For the year ended December 31, 2017, a $12.2 million loss was recorded upon HEP's redemption of its $300 million aggregate principal amount of 6.5% senior notes maturing March 2020 at a cost of $309.8 million.

For the year ended December 31, 2016, we recognized an $8.7 million loss on the early retirement of a financing obligation, a component of outstanding debt, upon HEP's purchase of crude oil tanks from an affiliate of Plains. See Note 12 "Debt" in the Notes to Consolidated Financial Statements for additional information on this financing obligation.

Gain (Loss) on Foreign Currency Swap
During the years ended December 31, 2017 and 2016, we recorded a $24.5 million gain and a $6.5 million loss, respectively, on currency swap contracts that effectively fixed the conversion rate on $1.125 billion Canadian dollars (the PCLI purchase price), which were settled on February 1, 2017, in connection with the closing of the PCLI acquisition.

Gain on Foreign Currency Transactions
Remeasurement adjustments resulting from the conversion of the intercompany financing structure on our PCLI acquisition from local currencies to the U.S. dollar resulted in a $16.9 million gain for the year ended December 31, 2017.

Income Taxes
For the year ended December 31, 2017, we recorded a net income tax benefit of $12.4 million compared to an income tax expense of $19.4 million for the year ended December 31, 2016. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were (1.4)% and (11.3)% for the years ended December 31, 2017 and 2016, respectively. During the year ended December 31, 2017, we recorded a tax benefit of $307.1 million as a result of the Tax Cut and Jobs Act which was enacted on December 22, 2017. During the year ended December 31, 2016, we recorded a $309.3 million goodwill impairment charge, a significant driver of our $171.5 million loss before income taxes for the year ended December 31, 2016, that is not deductible for income tax purposes.


Results of Operations – Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Summary
Net loss attributable to HollyFrontier stockholders for the year ended December 31, 2016 was $260.5 million ($1.48 per basic and diluted share), a $1,000.6 million decrease compared to net income attributable to HollyFrontier stockholders of $740.1 million ($3.91 per basic and $3.90 per diluted share) for the year ended December 31, 2015. Net income decreased due principally to non-cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million, respectively, and a year-over-year decrease in refining margins and sales volumes, net of the effects of a year-over-year change in lower of cost or market inventory reserve adjustments. For the year ended December 31, 2016, lower of cost or market inventory reserve adjustments increased pre-tax earnings by $291.9 million compared to a pre-tax earnings decrease of $227.0 million for the year ended December 31, 2015. Collectively, the impairment charges, net of the lower of cost or market valuation benefit, reduced 2016 pre-tax income by $362.1 million. Refinery gross margins for the year ended December 31, 2016 decreased to $8.16 per barrel sold from $15.88 for the year ended December 31, 2015.

Sales and Other Revenues
Sales and other revenues decreased 20% from $13,237.9 million for the year ended December 31, 2015 to $10,535.7 million for the year ended December 31, 2016 due to a year-over-year decrease in sales prices and lower product sales volumes. Sales and other revenues for the years ended December 31, 2016 and 2015 include $68.9 million and $66.7 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold
Total cost of products sold decreased 19% from $10,466.2 million for the year ended December 31, 2015 to $8,474.0 million for the year ended December 31, 2016, due principally to lower crude oil costs and lower sales volumes of products. Additionally, this decrease reflects a $291.9 million benefit that is attributable to a reduction in the lower of cost or market reserve for the year ended December 31, 2016, a $518.9 million increase compared to a charge of $227.0 million for the year ended December 31, 2015. The reserve at December 31, 2016 is based on market conditions and prices at that time.
Table of Content


Gross Refinery Margins
Gross refinery margin per barrel sold decreased 49% from $15.88 for the year ended December 31, 2015 to $8.16 for the year ended December 31, 2016. This was due to the effects of a decrease in the average per barrel sold sales price, partially offset by decreased crude oil and feedstock prices during the current year. Gross refinery margin does not include the non-cash effects of lower of cost or market inventory valuation adjustments, goodwill and asset impairment charges or depreciation and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.


Operating Expenses
Operating expenses, exclusive of depreciation and amortization, decreased 4%7% from $1,060.4$1,394.1 million for the year ended December 31, 20152019 to $1,018.8$1,300.3 million for the year ended December 31, 20162020 due principally to lower natural gas fuelrepair and maintenance costs comparedprimarily related to 2015. For the yearsshutdown of our Cheyenne Refinery, partially offset by decommissioning costs associated with the Cheyenne Refinery shutdown recorded in the year ended December 31, 2016 and 2015,2020. Prior year period operating expenses include $90.4 millionincluded higher repair and $102.3 million, respectively,maintenance costs related to a February 2019 fire in costs attributable to HEP operations.an FCC unit at our El Dorado Refinery.


Selling, General and Administrative Expenses
Selling, general and administrative expenses increased 4%decreased 11% from $120.8$354.2 million for the year ended December 31, 20152019 to $125.6$313.6 million for the year ended December 31, 2016,2020 due principally to pre-acquisitionlower professional services and employee-related expenses. We incurred $2.0 million and $24.2 million in direct acquisition and integration costs of PCLI. Forfor our Sonneborn business during the years ended December 31, 20162020 and 2015, general and administrative expenses include $10.1 million and $10.2 million, respectively, in costs attributable to HEP operations.2019.


Depreciation and Amortization Expenses
Depreciation and amortization increased 5%2% from $346.2$509.9 million for the year ended December 31, 20152019 to $363.0$520.9 million for the year ended December 31, 2016.2020. This increase was due principally to depreciation and amortization attributable to capitalized improvement projects and capitalized refinery turnaround costs. Forcosts, partially offset by lower depreciation expense resulting from the years ended December 31, 2016 and 2015, depreciation and amortization expenses include $68.8 million and $61.7 million, respectively,assets impaired in costs attributable to HEP operations.the current year period.

52
Table of Content

Goodwill and Long-lived Asset ImpairmentImpairments
During the year ended December 31, 2016,2020, we recorded goodwill and long-lived asset impairment charges of $309.3$232.2 million and $344.8 million, respectively, that relaterelated to our Cheyenne Refinery.Refinery, $26.5 million for construction-in-progress consisting primarily of engineering work for potential upgrades to certain processing units at our Tulsa and El Dorado Refineries and $204.7 million related to PCLI. Also, during the year ended December 31, 2020, we recorded a goodwill impairment charge of $81.9 million that related to Sonneborn. During the year ended December 31, 2019 we recorded a goodwill impairment charge of $152.7 million that related to PCLI. See Note 10 “Goodwill”11 “Goodwill, Long-lived Assets and Intangibles” in the Notes to Consolidated Financial Statements for additional information on the Cheyenne impairment.these impairments.


Interest Income
Interest income for the year ended December 31, 20162020 was $2.5$7.6 million compared to $3.4$22.1 million for the year ended December 31, 2015.2019. This decrease was primarily due to higher investment levels in marketable debt securities during 2015.lower interest rates on cash investments.


Interest Expense
Interest expense was $72.2$126.5 million for the year ended December 31, 20162020 compared to $43.5$143.3 million for the year ended December 31, 2015.2019. This increasedecrease was primarily due to lower market interest attributable to higher debt levels during 2016 relative to 2015.rates on HEP’s credit facility and HEP’s refinancing of its 6.0% senior notes due 2024, partially offset by interest expense on our senior notes issued in 2020. Additionally, we recorded unrealized losses on the mark-to-market change in the fair value of the embedded derivative in our catalyst financing arrangements of $4.3 million for the year ended December 31, 2020 and $6.4 million for the same period in 2019. For the years ended December 31, 20162020 and 2015,2019, interest expense included $52.6$52.9 million and $36.9$74.8 million, respectively, in interest costs attributable to HEP operations.


Gain on Business Interruption Insurance Settlement
During the year ended December 31, 2020, we recorded a gain of $81.0 million upon the settlement of our business interruption claim with our insurance carrier related to a loss at our Woods Cross Refinery that occurred in the first quarter of 2018.

Gain on Sales-type Leases
During the second quarter of 2020, HEP and Delek US Holdings, Inc. renewed the original throughput agreement on specific HEP assets. Portions of the new throughput agreement meet the definition of sales-type leases, which resulted in an accounting gain of $33.8 million upon the initial recognition of the sales-type lease during the year ended December 31, 2020.

Loss on Early Extinguishment of Debt
In March 2016, we recognized an $8.7For the year ended December 31, 2020, HEP recorded a $25.9 million loss on the early retirement of a financing obligation, a component of outstanding debt, upon HEP's purchase of crude oil tanks from an affiliate of Plains. See Note 12 “Debt” in the Notes to Consolidated Financial Statements for additional information on this financing obligation.

In June 2015, we recognized a $1.4 million early extinguishment loss on the redemption of our $150.0its $500 million aggregate principal amount of 6.875%6.0% senior notes maturing November 2018.August 2024 at a redemption cost of $522.5 million.


Gain on Foreign Currency Transactions
Remeasurement adjustments resulting from the foreign currency conversion of the intercompany financing notes payable by PCLI net of mark-to-market valuations on foreign exchange forward contracts with banks which hedge the foreign currency exposure on these intercompany notes were gains of $2.2 million and $5.4 million for the years ended December 31, 2020 and 2019, respectively. For the years ended December 31, 2020 and 2019, gain on foreign currency transactions included losses of $7.3 million and $17.4 million, respectively, on foreign exchange forward contracts (utilized as an economic hedge).

Income Taxes
For the year ended December 31, 2016,2020, we recorded an income tax benefit of $232.1 million compared to income tax expense of $19.4 million compared to $406.1$299.2 million for the year ended December 31, 2015.2019. This decrease was due principally to a pre-tax loss during the year ended December 31, 20162020 compared to pre-tax earnings duringfor the year ended 2015.December 31, 2019. Our effective tax rates before consideration ofwere 31.1% and 25.5% for the years ended December 31, 2020 and 2019, respectively. The year-over-year increase in the effective tax rate is due principally to the relationship between the pre-tax results and the earnings attributable to the noncontrolling interest were (11.3)% and 33.6% for the years ended December 31, 2016 and 2015, respectively. For the year ended December 31, 2016. the effective tax rate reflects the effects of the $309.3 million goodwill impairment charge, a significant driver of our $171.5 million loss before income taxes for the year ended December 31, 2016, that is not deductibleincluded in income for income tax purposes.purposes and benefits related to the CARES Act.


Table of Content



LIQUIDITY AND CAPITAL RESOURCES


HollyFrontier Credit Agreement
We have a $1.35 billion senior unsecured revolving credit facility maturing in February 2022 (the “HollyFrontier Credit Agreement”). The HollyFrontier Credit Agreement may be used for revolving credit loans and letters of credit from time to time and is available to fund general corporate purposes. During the year endedAt December 31, 2017, we received advances totaling $26.0 million and repaid $26.0 million under the HollyFrontier Credit Agreement. At December 31, 2017,2020, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $2.8$5.7 million under the HollyFrontier Credit Agreement.

53
Table of Content

HollyFrontier Senior Notes
On September 28, 2020, we completed a public offering of $350.0 million in aggregate principal amount of 2.625% senior notes maturing October 2023 and $400.0 million in aggregate principal amount of 4.500% senior notes maturing October 2030. We intend to use the net proceeds for general corporate purposes, which may include capital expenditures. These senior notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.

HollyFrontier Financing Arrangements
In December 2018, certain of our wholly-owned subsidiaries entered into financing arrangements whereby such subsidiaries sold a portion of their precious metals catalyst to a financial institution and then leased back the precious metals catalyst in exchange for total cash received of $32.5 million. The volume of the precious metals catalyst and the lease rate are fixed over the one-year term of each lease, and the lease payments are recorded as interest expense. The leases mature on February 1, 2022. Upon maturity, we must either satisfy the obligation at fair market value or refinance to extend the maturity.

HEP Credit Agreement
HEP has a $1.4 billion senior secured revolving credit facility maturing in July 2022 (the “HEP Credit Agreement”) and is available to fund capital expenditures, investments, acquisitions, distribution payments, working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and has a $300 million accordion. During the year ended December 31, 2017,2020, HEP received advances totaling $969.0$258.5 million and repaid $510.0$310.5 million under the HEP Credit Agreement. At December 31, 2017,2020, HEP was in compliance with all of its covenants, had outstanding borrowings of $1,012.0$913.5 million and no outstanding letters of credit under the HEP Credit Agreement.


HEP Senior Notes
In September 2017,On February 4, 2020, HEP issued an additional $100closed a private placement of $500.0 million in aggregate principal amount of 6.0%5.0% HEP senior unsecured notes maturing in August 2024 in a private placement. HEP used the net proceeds of $101.8 million to repay indebtedness under the HEP Credit Agreement.

In January 2017,February 2028. On February 5, 2020, HEP redeemed its $300existing $500.0 million aggregate principal amount of 6.50%6.0% senior notes maturing March 2020August 2024 at a redemption cost of $309.8 million, at which time$522.5 million. HEP recognized a $12.2$25.9 million early extinguishment loss consisting of a $9.8$22.5 million debt redemption premium and unamortized discount and financing costs of $2.4$3.4 million. HEP funded the $522.5 million redemption with proceeds from the issuance of its 5.0% senior notes and borrowings under the HEP Credit Agreement.


See Note 12 "Debt"13 “Debt” in the Notes to Consolidated Financial Statements for additional information on our debt instruments.


HEP Common Unit Continuous Offering Program
OnIn May 10, 2016, HEP established a continuous offering program under 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. During the year ended December 31, 2017,2020, HEP did not issue any common units under this program. As of December 31, 2020, HEP has issued 1,538,4522,413,153 common units under this program, providing $52.1$82.3 million in netgross proceeds. In connection with this program and to maintain our then economic 2% general partner interest in HEP, we made capital contributions totaling $1.1 million during the year ended December 31, 2017. As of December 31, 2017, HEP has issued 2,241,907 common units with an aggregate gross sales amount of $77.1 million.

HEP intends to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. Amounts repaid under HEP’s credit facility may be reborrowed from time to time.

HEP Private Placement Agreement
On January 25, 2018, HEP entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 HEP common units, representing limited partner interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, at which time HEP received proceeds of approximately $110.0 million, which were used to repay indebtedness under the HEP Credit Agreement. After this common unit issuance, our limited partner interest in HEP is 57%.


Liquidity
We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our credit facilities, will provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets. In addition, subject to our current cash conservation strategies as discussed above in “Outlook,” components of our growth strategy include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. We also expect to use cash for payment of cash dividends, which are at the discretion of our Board of Directors, and, once commodity prices and demand for products normalize, for the repurchases of our common stock under our share repurchase program.


Table of Content

As of Our standalone (excluding HEP) liquidity was approximately $2.70 billion at December 31, 2017, our2020, consisting of cash and cash equivalents totaled $630.8 million. of $1.35 billion and an undrawn $1.35 billion credit facility.

We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value. These primarily consist of investments in conservative, highly-rated instruments issued by financial institutions, government and corporate entities with strong credit standings and money market funds.


On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor to acquire 100%
54
Table of the outstanding capital stock of PCLI. The acquisition closed on February 1, 2017. Cash consideration paid was $862.1 million, or $1.125 billion in Canadian dollars.Content

In May 2015,November 2019, our Board of Directors approved a $1$1.0 billion share repurchase program, which replaced all existing share repurchase programs, authorizing us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions and corporate, regulatory and other relevant considerations. This program may be discontinued at any time by our Board of Directors. As of December 31, 2017,2020, we had remaining authorization to repurchase up to $178.8 millionnot repurchased common stock under this stock repurchase program. In addition, we are authorized by our Board of Directors to repurchase shares in an amount sufficient to offset shares issued under our compensation programs. We do not intend to repurchase common stock under our $1.0 billion share repurchase program until commodity prices and demand for products normalize.


Cash and cash equivalents decreased $79.8increased $483.2 million for the year ended December 31, 2017.2020. Net cash provided by operating and financing activities of $457.9 million and $353.2 million, respectively, exceeded cash used for investing and financing activities of $959.7$330.2 million and $72.6 million, respectively, exceeded net cash provided by operating activities of $951.4 million. Working capital decreased by $127.7 million duringfor the year ended December 31, 2017.2020.


Cash Flows – Operating Activities


Year Ended December 31, 20172020 Compared to Year Ended December 31, 20162019
Net cash flows provided by operating activities were $951.4$457.9 million for the year ended December 31, 20172020 compared to $606.9$1,548.6 million for the year ended December 31, 2016, an increase 2019, a decrease of $344.4 million.$1,090.7 million. Net incomeloss for the year ended December 31, 20172020 was $881.2$514.9 million,, an increase a decrease of $1,072.2$1,387.3 million compared to net lossincome of $190.9$872.4 million for the year ended December 31, 2016.2019. Non-cash adjustments to net income / loss consisting of depreciation and amortization, goodwill and long-lived asset impairment,impairments, lower of cost or market inventory valuation adjustment, earnings of equity method investments, inclusive of distributions, loss on early extinguishment of debt, gain on equity company acquisition,sales-type leases, gain or/ loss on sale of assets, loss on extinguishment of debt, deferred income taxes, equity-based compensation expense and fair value changes to derivative instruments and excess tax expense from equity-based compensation totaled $225.5 million for the year ended December 31, 2017 compared to $842.6 million for the same period in 2016. Changes in working capital items decreased cash flows by $6.1 million for the year ended December 31, 2017, and increased cash flows by $74.7 million for the year ended December 31, 2016. For the year ended December 31, 2017, turnaround expenditures increased to $135.1 million from $125.3 million for the same period of 2016.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Net cash flows provided by operating activities were $606.9$1,019.1 million for the year ended December 31, 20162020 compared to $985.9$700.5 million for the same period in 2019. Adjusted for non-cash items, changes in working capital increased operating cash flows by $43.5 million and $312.8 million for the years ended December 31, 2020 and 2019, respectively. Additionally, for the year ended December 31, 2015, a decrease of $378.9 million. Net loss for the year ended December 31, 2016 was $190.9 million, a decrease of $993.5 million compared to net income of $802.5 million for the year ended December 31, 2015. Non-cash adjustments to net income consisting of depreciation and amortization, goodwill and asset impairment, lower of cost or market inventory valuation adjustment, earnings of equity method investments, inclusive of distributions, gain on sale of assets, gain or loss on extinguishment of debt, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and excess tax expense from equity-based compensation totaled $842.6 million for the year ended December 31, 2016 compared to $492.0 million for the same period in 2015. Changes in working capital items increased cash flows by $74.7 million for the year ended December 31, 2016 compared to a decrease of $195.1 million for the year ended December 31, 2015. For the year ended December 31, 2016,2020, turnaround expenditures increaseddecreased to $125.3$94.7 million from $89.4$318.4 million for the same period of 2015.2019.

Table of Content


Cash Flows – Investing Activities and Planned Capital Expenditures


Year Ended December 31, 20172020 Compared to Year Ended December 31, 2016
Net cash flows used for investing activities were $959.7 million for the year ended December 31, 2017 compared to $801.6 million for the year ended December 31, 2016, an increase of $158.1 million. Current year investing activities reflect a net cash outflow of $870.6 million upon the acquisition of PCLI. Cash expenditures for properties, plants and equipment for 2017 decreased to $272.3 million from $479.8 million for the same period in 2016. These include HEP capital expenditures of $44.8 million and $107.6 million for the years ended December 31, 2017 and 2016, respectively. In addition, in 2017, HEP purchased the remaining interests in SLC Pipeline and Frontier Pipeline for $245.4 million. In 2016, HEP purchased a 50% interest in Cheyenne Pipeline for $42.6 million. We received proceeds of $1.4 million and $0.8 million from the sale of assets during the years ended December 31, 2017 and 2016, respectively. For the years ended December 31, 2017 and 2016, we invested $41.6 million and $546.6 million, respectively, in marketable securities and received proceeds of $465.7 million and $266.6 million, respectively, from the sale or maturity of marketable securities.

Year Ended December 31, 2016 Compared to Year Ended December 31, 20152019
Net cash flows used for investing activities were $801.6$330.2 million for the year ended December 31, 20162020 compared to $381.7$972.9 million for the year ended December 31, 2015, an increase2019, a decrease of $419.8$642.8 million, primarily driven by prior year investing activity reflecting the acquisition of Sonneborn for a net cash outflow of $662.7 million. Cash expenditures for properties, plants and equipment for 2016 decreased2020 increased to $479.8$330.2 million from $676.2$293.8 million for the same period in 2015.2019. These include HEP capital expenditures of $107.6$59.3 million and $193.1$30.1 million for the years ended December 31, 20162020 and 2015,2019, respectively. In addition, in 2016, :HEP purchased a 50% interest in Cheyenne Pipeline for $42.6Additionally, HEP invested $2.4 million and $17.9 million in 2015, a 50% interest in Frontierthe Cushing Connect Pipeline & Terminal LLC joint venture for $55.0 million. We received proceeds of $0.8 million and $19.3 million from the sale of assets during the years endedending December 31, 20162020 and 2015,2019, respectively. For the years ended December 31, 2016 and 2015, we invested $546.6 million and $509.3 million, respectively, in marketable securities and received proceeds of $266.6 million and $839.5 million, respectively, from the sale or maturity of marketable securities.

Planned Capital Expenditures


HollyFrontier Corporation
Each year our Board of Directors approves our annual capital budget which includes specific projects that management is authorized to undertake. Additionally, when conditions warrant or as new opportunities arise, additional projects may be approved. The funds appropriated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures appropriated in that year’s capital budget plus expenditures for projects appropriated in prior years which have not yet been completed. During 2018, we expect to spend approximately $425.0 million to $500.0 million in cash for capital projects and refinery turnarounds appropriated in 2018 and prior years. Refinery turnaround spending is amortized over the useful life of the turnaround. Our expected capital and turnaround cash spending for 2018 is as follows:
 Expected Cash Spending Range
 (In millions)
Type:   
Capital$225.0
 $280.0
Turnarounds200.0
 220.0
Total$425.0
 $500.0


The refining industry is capital intensive and requires on-going investments to sustain our refining operations. This includes replacement of, or rebuilding, refinery units and components that extend the useful life. We also invest in projects that improve operational reliability and profitability via enhancements that improve refinery processing capabilities as well as production yield and flexibility. Our capital expenditures also include projects related to renewable diesel, environmental, health and safety compliance and include initiatives as a result of federal and state mandates.


A significant portion of our current capital spending is associated with compliance-oriented capital improvements. This spending is required due to existing consent decrees (for projects including FCC unit flue gas scrubbers and tail gas treatment units), federal fuels regulations (particularly, Tier 3 which mandates a reduction in the sulfur content of blended gasoline), refinery waste water treatment improvements and other similar initiatives. Our refinery operations and related emissions are highly regulated at both federal and state levels, and we invest in our facilities as needed to remain in compliance with these standards. Additionally, when faced with new emissions or fuels standards, we seek to execute projects that facilitate compliance and also improve the operating costs and / or yields of associated refining processes.


55
Table of Content

HEP
Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special 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, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in its current year capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. In addition, HEP may spend funds periodically to perform capital upgrades or additions to its assets where a customer reimburses HEP for such costs. The 2018 HEP capital budget is comprised of $8.0 million for maintenance capital expenditures and $40.0 million for expansion capital expenditures. HEP expectsupgrades or additions would generally benefit the majoritycustomer over the remaining life of the expansionrelated service agreements.

Expected capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks, and enhanced blending capabilities at our racks.turnaround cash spending for 2021 is as follows:

Expected Cash Spending Range
(In millions)
HollyFrontier Capital Expenditures
Refining$190.0 $220.0 
Renewable Diesel Units520.0 550.0 
Lubricants and Specialty Products40.0 50.0 
Turnarounds and catalyst320.0 350.0 
Total HollyFrontier1,070.0 1,170.0 
HEP
Maintenance14.0 18.0 
Expansion and joint venture investment30.0 35.0 
Refining unit turnarounds5.0 8.0 
Total HEP49.0 61.0 
Total$1,119.0 $1,231.0 

Cash Flows – Financing Activities


Year Ended December 31, 20172020 Compared to Year Ended December 31, 20162019
Net cash flows used forprovided by financing activities were $72.6$353.2 million for the year ended December 31, 20172020 compared to net cash flows provided byused for financing activities of $838.7$848.3 million for the year ended December 31, 2016,2019, an increase of $911.3$1,201.5 million. During the year ended December 31, 2017,2020, we received $26.0$742.1 million in net proceeds from the issuance of HFC’s 2.625% and repaid $26.04.500% senior notes, purchased $7.6 million under the HollyFrontier Credit Agreementof treasury stock and paid $235.5$229.5 million in dividends. Also during this period, HEP received $969.0$258.5 million and repaid $510.0$310.5 million under the HEP Credit Agreement, received $101.8 million in net proceeds from issuance of HEP 6.0% senior notes, paid $309.8$522.5 million upon the redemption of HEP's 6.5%HEP’s 6.0% senior notes and received $52.1$491.3 million in net proceeds from the issuance of its common units andHEP 5.0% senior notes, paid distributions of $110.4$89.0 million to noncontrolling interests. In addition, for the years ended December 31, 2017interests and 2016, $15.9 million and $4.7 million, respectively,received contributions from noncontrolling interests of vested shares under our stock compensation plans were withheld for tax withholding obligations. During the year ended December 31, 2016, we received $992.6 million in net proceeds upon issuance of our 5.875% senior notes, received $350.0 million and repaid $350.0 million under a term loan, received $315.0 million and repaid $315.0 million under the HollyFrontier Credit Agreement, purchased $133.4 million in common stock and paid $234.0 million in dividends. In addition, we extinguished our financing obligation with Plains for $39.5 million. Also during this period, HEP received $554.0 million and repaid $713.0 million under the HEP Credit Agreement, received $394.0 million in net proceeds from issuance of HEP 6.0% senior notes, received $125.9 million in net proceeds from the issuance of its common units and paid distributions of $92.6 million to noncontrolling interests.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Net cash flows provided by financing activities were $838.7 million for the year ended December 31, 2016 compared to cash flows used for financing activities of $1,105.6 million for the year ended December 31, 2015, an increase of $1,944.3$23.9 million. During the year ended December 31, 2016,2019, we received $992.6purchased $533.1 million of treasury stock and paid $225.2 million in net proceeds upon issuance of our 5.875% senior notes,dividends. Also during 2019, HEP received $350.0$365.5 million and repaid $350.0 million under a term loan, received $315.0 million and repaid $315.0 million under the HollyFrontier Credit Agreement, purchased $133.4 million in common stock and paid $234.0 million in dividends. In addition, we extinguished our financing obligation with Plains for $39.5 million. In addition, we withheld shares to pay employee income taxes of $4.7 million for the year ended December 31, 2016, and $6.2 million for the year ended December 31, 2015. Also during this period, HEP received $554.0 million and repaid $713.0$323.0 million under the HEP Credit Agreement, received $394.0 million in net proceeds from issuance of HEP 6.0% senior notes, received $125.9 million in net proceeds from the issuance of its common units and paid distributions of $92.6$132.3 million to noncontrolling interests. During the year ended December 31, 2015, we purchased $742.8interests and received a contribution of $3.2 million in common stock, paid $246.9 million in dividends and paid $155.2 million upon the redemption of our 6.875% senior notes. Also during this period, HEP received $973.9 million and repaid $832.9 million under the HEP Credit Agreement and paid distributions of $83.3 million tofrom noncontrolling interests.


56
Table of Content

Contractual Obligations and Commitments


The following table presents our long-term contractual obligations as of December 31, 20172020 in total and by period due beginning in 2018.2021. The table below does not include our contractual obligations to HEP under our long-term transportation agreements as these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” Also,
Payments Due by Period
Contractual Obligations and CommitmentsTotal20212022 & 20232024 & 2025Thereafter
(In thousands)
HollyFrontier Corporation
Long-term debt - principal (1)
$1,750,000 $— $350,000 $— $1,400,000 
Long-term debt - interest (2)
509,203 85,937 169,578 153,500 100,188 
Financing arrangements (3)
43,948 43,948 — — — 
Supply agreements (4)
1,487,924 538,616 506,011 443,297 — 
Transportation and storage agreements (5)
1,163,751 129,661 226,648 226,553 580,889 
Operating and finance leases (6)
352,838 103,593 154,585 52,463 42,197 
Other long-term obligations31,597 14,422 15,304 1,579 292 
5,339,261 916,177 1,422,126 877,392 2,123,566 
Holly Energy Partners
Long-term debt - principal (7)
1,413,500 — 913,500 — 500,000 
Long-term debt - interest (8)
207,283 44,200 61,000 50,000 52,083 
Operating and finance leases (6)
113,061 8,383 15,802 14,222 74,654 
Other agreements3,310 1,933 1,377 — — 
1,737,154 54,516 991,679 64,222 626,737 
Total$7,076,415 $970,693 $2,413,805 $941,614 $2,750,303 

(1)Our long-term debt consists of the table below does not reflect renewal options$350.0 million principal balance on our operating leases2.625% senior notes, $1.0 billion principal balance on our 5.875% senior notes and $400.0 million principal balance on our 4.500% senior notes.
(2)Interest payments consist of interest on our 2.625% senior notes, 5.875% senior notes and 4.500% senior notes.
(3)We have a financing arrangement related to the sale and subsequent lease-back of certain of our precious metals.
(4)We have long-term supply agreements to secure certain quantities of crude oil, feedstock and other resources used in the production process at market prices. We have estimated future payments under these fixed-quantity agreements expiring between 2021 and 2025 using current market rates. Additionally, commitments include purchases of 20,000 BPD of crude oil under a 10-year agreement that commenced in 2015 to supply our Woods Cross Refinery.
(5)Consists of contractual obligations under agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries and for terminal and storage services under contracts expiring between 2021 and 2039.
(6)Operating and finance lease obligations include options to extend terms that are likely to bereasonably certain of being exercised.
(7)HEP's long-term debt consists of the $500.0 million principal balance on the 5.0% HEP senior notes and $913.5 million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement expires in 2022.
    Payments Due by Period
Contractual Obligations and Commitments Total Less than 1 Year 1-3 Years 3-5 Years Over 5 Years
  (In thousands)
HollyFrontier Corporation          
Long-term debt - principal $1,000,000
 $—
 $—
 $—
 $1,000,000
Long-term debt - interest (1)
 489,583
 58,750
 117,500
 117,500
 195,833
Supply agreements (2)
 2,853,780
 526,759
 744,057
 672,713
 910,251
Transportation and storage agreements (3)
 1,407,602
 142,291
 239,336
 197,434
 828,541
Other long-term obligations 29,232
 11,593
 14,055
 1,584
 2,000
Operating leases 421,344
 80,904
 143,832
 108,931
 87,677
  6,201,541
 820,297
 1,258,780
 1,098,162
 3,024,302
           
Holly Energy Partners          
Long-term debt - principal (4)
 1,512,000
 —
 —
 1,012,000
 500,000
Long-term debt - interest (5)
 370,300
 67,800
 135,600
 119,400
 47,500
Pipeline operating leases 61,038
 6,425
 12,850
 12,850
 28,913
Operating leases 4,858
 1,441
 1,809
 659
 949
Other agreements 7,872
 1,652
 3,304
 2,916
 —
  1,956,068
 77,318
 153,563
 1,147,825
 577,362
Total $8,157,609
 $897,615
 $1,412,343
 $2,245,987
 $3,601,664
(8)Interest payments consist of interest on the 5.0% HEP senior notes and interest on long-term debt under the HEP Credit Agreement. Interest on the HEP Credit Agreement debt is based on the weighted average rate of 2.10% at December 31, 2020.

(1)Interest payments consist of interest on our 5.875% senior notes.
(2)We have long-term supply agreements to secure certain quantities of crude oil, feedstock and other resources used in the production process at market prices. We have estimated future payments under these fixed-quantity agreements expiring between 2018 and 2030 using current market rates. Additionally, commitments include purchases of 20,000 BPD of crude oil under a 10-year agreement to supply our Woods Cross Refinery.
(3)Consists of contractual obligations under agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries and for terminal and storage services under contracts expiring between 2018 and 2030.
(4)HEP's long-term debt consists of the $500.0 million principal balance on the 6% HEP senior notes and $1,012.0 million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement expires in 2022.
(5)Interest payments consist of interest on the 6% HEP senior notes and interest on long-term debt under the HEP Credit Agreement. Interest on the HEP Credit Agreement debt is based on the weighted average rate of 3.73% at December 31, 2017.




CRITICAL ACCOUNTING POLICIES


Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. 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. For additional information, see Note 1 “Description of Business and Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements.


57
Table of Content

Inventory Valuation
Inventories related to our refining operations are stated at the lower of cost, using the LIFO method for crude oil and unfinished and finished refined products, or market. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. At December 31, 20172020 and 2016,2019, market values had fallen below historical LIFO inventory costs and, as a result, we recorded lower of cost or market inventory valuation reserves of $223.8$318.9 million and $332.5$240.4 million, respectively.


At December 31, 2017,2020, our lower of cost or market inventory valuation reserve was $223.8$318.9 million. This amount, or a portion thereof, is subject to reversal as a reduction to cost of products sold in subsequent periods as inventories giving rise to the reserve are sold, and a new reserve is established. Such a reduction to cost of products sold could be significant if inventory values return to historical cost price levels. Additionally, further decreases in overall inventory values could result in additional charges to cost of products sold should the lower of cost or market inventory valuation reserve be increased.


Inventories consisting of process chemicals, materials and maintenance supplies and RINs are stated at the lower of weighted-average cost or net realizable value. Inventories of our Petro-Canada Lubricants and Sonneborn businesses are stated at the lower of cost, using the FIFO method, or net realizable value.

In connection with our announcement of the conversion of our Cheyenne Refinery to renewable diesel production, we recorded a reserve of $9.0 million for the year ended December 31, 2020 against our repair and maintenance supplies inventory.

Goodwill and Long-lived Assets
As of December 31, 2017,2020, our goodwill balance was $2.2$2.3 billion, with goodwill assigned to our Refining, Lubricants and Specialty Products and HEP segments of $1.7 billion, $0.2 billion$1,733.5 million, $247.6 million and $0.3 billion,$312.9 million, respectively. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired and liabilities assumed. Goodwill is not subject to amortization and is tested annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Our goodwill impairment testing first entails either a comparisonquantitative assessment or an optional qualitative assessment to determine whether it is more likely than not that the fair value of oura reporting unit fair values relative to their respectiveis less than its carrying values.amount. If we determine that based on the qualitative factors that it is more likely than not that the carrying value exceedsof the reporting unit is greater than its fair value, fora quantitative test is performed in which we estimate the fair value of the related reporting unit. If the carrying amount of a reporting unit exceeds its fair value, the goodwill of that reporting unit is impaired, and we measure goodwill impairment as the excess of the carrying amount of reporting unit goodwill over the impliedrelated fair valuevalue.

For purposes of that goodwill based on estimates of the fair value of all assets and liabilities in the reporting unit.

Ourlong-lived asset impairment evaluation, we have grouped our long-lived assets principally consist ofas follows: (i) our refining assets that are organized as refiningrefinery asset groups, and thewhich include certain HEP logistics assets, of(ii) our Lubricants and Specialty Products business. Theasset groups and (iii) our HEP asset groups, which comprises HEP assets not included in our refinery asset groups. These asset groups also constitute our individual refinery reporting units that are usedrepresent the lowest level for testing and measuring goodwill impairments.which independent cash flows can be identified. Our long-lived assets are evaluated for 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 measured, if any, is equal to the amount by which the asset group’s carrying value exceeds its fair value.


WeGoodwill and long-lived asset impairments
During the second quarter of 2020, we determined that indicators of potential goodwill and long-lived asset impairments were present and performed recoverability testing for long-lived assets and an interim test for goodwill impairment as of May 31, 2020. Impairment indicators included the recent economic slowdown caused by the COVID-19 pandemic, reductions in the prices of our finished goods and raw materials and the related decrease in our gross margins, as well as the recent decline in our market capitalization. Additionally, our second quarter announcement of the planned conversion of our Cheyenne Refinery to renewable diesel production was also considered a triggering event requiring assessment of potential impairments to the carrying value of our Cheyenne Refinery asset group. As a result of our long-lived asset recoverability testing, we determined that the carrying value of the long-lived assets of our Cheyenne Refinery and PCLI asset groups were not recoverable, and thus recorded long-lived asset impairment charges of $232.2 million and $204.7 million, respectively, in the second quarter of 2020. Our interim goodwill impairment testing indicated that there was no impairment of goodwill at our Refining and Lubricants and Specialty Products reporting units as of May 31, 2020. The estimated fair values of the Cheyenne Refinery and PCLI asset groups were determined using a combination of the income and cost approaches. The income approach was based on management’s best estimates of the expected future cash flows over the remaining useful life of the asset group. The cost approach utilized assumptions for the current replacement costs of similar assets adjusted for estimated depreciation and economic obsolescence.
58
Table of Content

As of July 1, 2020, we performed our annual goodwill impairment testing quantitatively and determined there was no impairment of goodwill attributable to our reporting units at that time. The excess of the fair values of the reporting units over their respective carrying values ranged from 10% to 229%. Increasing the discount rate by 1.0% or reducing the terminal cash flow growth rate by 1.0% would not have changed the results of our goodwill impairment testing performed in the second and third quarters of 2020.

During the fourth quarter of 2020, we incurred long-lived asset impairment charges of $26.5 million for construction-in-progress, consisting primarily of engineering work for potential upgrades to certain processing units at our Tulsa and El Dorado Refineries. During the quarter, we concluded not to pursue these projects in light of recent economic and market conditions.

Additionally, in the fourth quarter of 2020, our budgeting processes identified downward forecast revisions specific to the Sonneborn reporting unit within our Lubricants and Specialty Products segment largely from declines in gross margin as compared to historic levels and an increase in forecasted capital expenditures. As such, we concluded it was more likely than not that the carrying value of the Sonneborn reporting unit exceeded its fair value, and we performed an interim quantitative test for goodwill impairment as of December 1, 2020. As a result of our impairment testing, we recognized a goodwill impairment charge of $81.9 million during the fourth quarter for the Sonneborn reporting unit. Our annual test performed on July 1, 2017 and determined2020 indicated that the fair value of our El Dorado reporting unit exceeded its carrying value by approximately 10%. However, based on our reviews of updated budgets, and other factors such as economic and industry conditions we concluded that El Dorado and our other reporting units within our Lubricants and Specialty Products segment did not require an interim impairment test during the fourth quarter.

We continually monitor and evaluate various factors for potential indicators of goodwill and long-lived asset impairment. A reasonable expectation exists that futurefurther deterioration in gross marginsour operating results or overall economic conditions could result in an impairment of goodwill and the/ or additional long-lived assets of the El Dorado reporting unitasset impairments at some point in the future and suchfuture. Future impairment charges could be material. Additionally, qualitative testing indicated no impairment of goodwill attributablematerial to our otherresults of operations and financial condition.

In performing our impairment tests of long-lived assets and goodwill, we developed cash flow forecasts for each of our asset groups and reporting units. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted financial information. The cash flow forecasts include significant assumptions such as planned utilization, end user demand, selling prices, gross margins, operating costs and capital expenditures. Another key assumption applied to these forecasts to determine the fair value of an asset group or reporting unit is the discount rate. The discount rate is intended to reflect the weighted average cost of capital for a market participant and the risks associated with the realization of the estimated future cash flows. Assumptions about the effects of the COVID-19 pandemic on future demand and market conditions are inherently subjective and difficult to forecast. Our fair value estimates are based on projected cash flows, which we believe to be reasonable.


Contingencies
We 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 matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these 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 matters.




RISK MANAGEMENT


We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit.


Commodity Price Risk Management
Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative contracts in the form of commodity price swaps, forward purchase and sales and futures contracts to mitigate price exposure with respect to:
to our inventory positions;
positions, natural gas purchases;purchases, sales prices of refined products and crude oil costs.

59
Table of Content

Foreign Currency Risk Management
costsWe are exposed to market risk related to the volatility in foreign currency exchange rates. We periodically enter into derivative contracts in the form of crude oilforeign exchange forward and related grade differentials;foreign exchange swap contracts to mitigate the exposure associated with fluctuations on intercompany notes with our foreign subsidiaries that are not denominated in the U.S. dollar.
prices of refined products; and
our refining margins.

As of December 31, 2017,2020, we have the following notional contract volumes related to all outstanding derivative contracts used to mitigate commodity price risk:and foreign currency risk ( all maturing in 2021):
Contract DescriptionTotal Outstanding NotionalUnit of Measure
Natural gas price swaps - long1,800,000 MMBTU
NYMEX futures (WTI) - short160,000 Barrels
Forward gasoline and diesel contracts - long195,000 Barrels
Foreign currency forward contracts418,192,532 U.S. dollar
Forward commodity contracts (platinum) (1)
40,867 Troy ounces
    Notional Contract Volumes by Year of Maturity  
Contract Description Total Outstanding Notional 2018 2019 2020 2021 Unit of Measure
             
Natural gas price swaps - long 7,200,000
 1,800,000
 1,800,000
 1,800,000
 1,800,000
 MMBTU
NYMEX futures (WTI) - short 1,175,000
 1,175,000
 —
 —
 —
 Barrels
Forward gasoline and diesel contracts - long 85,000
 85,000
 —
 —
 —
 Barrels
Forward gasoline and diesel contracts - short 250,000
 250,000
 —
 —
 —
 Barrels
Forward crude oil contracts - short 276,751
 276,751
 —
 —
 —
 Barrels


(1) Represents an embedded derivative within our catalyst financing arrangements, which may be refinanced or require repayment under certain conditions. See Note 13 “Debt” in the Notes to Consolidated Financial Statements for additional information on these financing arrangements.

The following sensitivity analysis provides the hypothetical effects of market price fluctuations to the commodity positions hedged under our derivative contracts:
Estimated Change in Fair Value at December 31,
Derivative Contracts20202019
(In thousands)
Hypothetical 10% change in underlying commodity prices$344 $7,420 
  Estimated Change in Fair Value at December 31,
Commodity-based Derivative Contracts 2017 2016
  (In thousands)
Hypothetical 10% change in underlying commodity prices $5,451
 $2,272


Interest Rate Risk Management
The market risk inherent in our fixed-rate debt is the potential change arising from increases or decreases in interest rates as discussed below.


For the fixed rate HollyFrontier Senior Notes and HEP Senior Notes, changes in interest rates will generally affect fair value of the debt, but not earnings or cash flows. The outstanding principal, estimated fair value and estimated change in fair value (assuming a hypothetical 10% change in the yield-to-maturity rates) for this debt as of December 31, 20172020 is presented below:
Outstanding
Principal		Estimated
Fair Value		Estimated
Change in
Fair Value
 (In thousands)
HollyFrontier Senior Notes$1,750,000 $1,903,867 $31,428 
HEP Senior Notes$500,000 $506,540 $14,535 
  
Outstanding
Principal
 
Estimated
Fair Value
 
Estimated
Change in
Fair Value
  (In thousands)
HollyFrontier Senior Notes $1,000,000
 $1,113,470
 $31,201
HEP Senior Notes $500,000
 $525,120
 $14,603


For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2017,2020, outstanding borrowings under the HEP Credit Agreement were $1,012.0 million. were $913.5 million. A hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.


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


Financial information is reviewed on the counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the derivative contracts. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their commitments.

60
Table of Content

We have a risk management oversight committee consisting of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.
Table of Content





Item 7A.Quantitative and Qualitative Disclosures About Market Risk

Item 7A.Quantitative and Qualitative Disclosures About Market Risk

See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”




Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles


Reconciliations of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.


Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income (loss) attributable to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation isare derived from amounts included in our consolidated financial statements. EBITDA should not be considered 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. 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 financial covenants.


Set forth below is our calculation of EBITDA.
Years Ended December 31,
 202020192018
 (In thousands)
Net income (loss) attributable to HollyFrontier stockholders$(601,448)$772,388 $1,097,960 
Add (subtract) income tax provision(232,147)299,152 347,243 
Add interest expense126,527 143,321 131,363 
Subtract interest income(7,633)(22,139)(16,892)
Add depreciation and amortization520,912 509,925 437,324 
EBITDA$(193,789)$1,702,647 $1,996,998 
  Years Ended December 31,
  2017 2016 2015
  (In thousands)
Net income (loss) attributable to HollyFrontier stockholders $805,395
 $(260,453) $740,101
Add (subtract) income tax provision (12,379) 19,411
 406,060
Add interest expense (1)
 129,822
 80,910
 44,840
Subtract interest income (3,736) (2,491) (3,391)
Add depreciation and amortization 409,937
 363,027
 346,151
EBITDA $1,329,039
 $200,404
 $1,533,761

(1) Includes loss on early extinguishment of debt of $12.2 million, $8.7 million and $1.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.


Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally accepted accounting principles in financial statements.


Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis. Refinery gross margin per produced barrel sold is total refining segment revenues less total refining segment cost of products sold, exclusive of lower of cost or market inventory valuation adjustments, divided by sales volumes of produced refined products sold. Net operating margin per barrel sold is the difference between refinery gross margin and refinery operating expenses per produced barrel sold. These two margins do not include the non-cash effects of long-lived asset impairment charges, lower of cost or market inventory valuation adjustments goodwill and asset impairment charges or depreciation and amortization. Each of these component performance measures can be reconciled directly to our consolidated statements of income. Other companies in our industry may not calculate these performance measures in the same manner.


Below are reconciliations to our consolidated statements of income for refinery net operating and gross margin and operating expenses, in each case averaged per produced barrel sold. Due to rounding of reported numbers, some amounts may not calculate exactly.


61
Table of Content

Reconciliation of average refining segment net operating margin per produced barrel sold to refinery gross margin to total sales and other revenues
Years Ended December 31,
 202020192018
 (Dollars in thousands, except per barrel amounts)
Consolidated
Net operating margin per produced barrel sold$1.24 $9.80 $10.44 
Add average refinery operating expenses per produced barrel sold6.05 6.12 6.06 
Refinery gross margin per produced barrel sold$7.29 $15.92 $16.50 
Times produced barrels sold (BPD)391,670 414,370 408,390 
Times number of days in period366 365 365 
Refining gross margin$1,045,030 $2,407,821 $2,459,529 
Add (subtract) rounding523 215 285 
West and Mid-Continent regions gross margin1,045,553 2,408,036 2,459,814 
Add West and Mid-Continent regions cost of products sold7,992,047 12,062,661 12,313,533 
Add Cheyenne Refinery sales and other revenues501,589 1,126,091 1,403,216 
Refining segment sales and other revenues9,539,189 15,596,788 1559678800016,176,563 
Add lubricants and specialty products segment sales and other revenues1,803,210 2,092,528 1,812,703 
Add HEP segment sales and other revenues497,848 532,777 506,220 
Subtract corporate, other and eliminations(656,604)(735,515)(780,820)
Sales and other revenues$11,183,643 $17,486,578 $17,714,666 
  Years Ended December 31,
  2017 2016 2015
  (Dollars in thousands, except per barrel amounts)
Consolidated      
Net operating margin per produced barrel sold $5.46
 $2.52
 $10.06
Add average refinery operating expenses per produced barrel sold 6.10
 5.64
 5.82
Refinery gross margin per produced barrel sold 11.56
 8.16
 15.88
Times produced barrels sold (BPD) 452,270
 440,640
 442,650
Times number of days in period 365
 366
 365
Refining segment gross margin 1,908,308
 1,315,998
 2,565,688
Add rounding 409
 1,212
 1,156
Total refining segment gross margin 1,908,717
 1,317,210
 2,566,844
Add refining segment cost of products sold 11,009,345
 9,003,505
 10,472,268
Refining segment sales and other revenues 12,918,062
 10,320,715
 13,039,112
Add lubricants and specialty products segment sales and other revenues 1,594,036
 464,359
 493,282
Add HEP segment sales and other revenues 454,362
 402,043
 358,875
Subtract corporate, other and eliminations (715,161) (651,417) (653,349)
Sales and other revenues $14,251,299
 $10,535,700
 $13,237,920



Reconciliation of average refining segment operating expenses per produced barrel sold to total operating expenses

Years Ended December 31,
 202020192018
 (Dollars in thousands, except per barrel amounts)
Consolidated
Average refinery operating expenses per produced barrel sold$6.05 $6.12 $6.06 
Times produced barrels sold (BPD)391,670 414,370 408,390 
Times number of days in period366 365 365 
Refinery operating expenses$867,275 $925,620 $903,318 
Add (subtract) rounding(381)(338)(162)
West and Mid-Continent regions operating expenses866,894 925,282 903,156 
Add Cheyenne Refinery operating expenses121,151 170,206 152,053 
Total refining segment operating expenses988,045 1,095,488 1,055,209 
Add lubricants and specialty products segment operating expenses216,068 231,523 167,820 
Add HEP segment operating expenses147,692 161,996 146,430 
Subtract corporate, other and eliminations(51,528)(94,955)(83,621)
Operating expenses (exclusive of depreciation and amortization)$1,300,277 $1,394,052 $1,285,838 

62
  Years Ended December 31,
  2017 2016 2015
  (Dollars in thousands, except per barrel amounts)
Consolidated      
Average refining operating expenses per barrel sold $6.10
 $5.64
 $5.82
Times barrels sold (BPD) 452,270
 440,640
 442,650
Times number of days in period 365
 366
 365
Refinery operating expenses 1,006,979
 909,587
 940,321
Add (subtract) rounding (304) 137
 308
Total refining segment operating expenses 1,006,675
 909,724
 940,629
Add lubricants and specialty products segment operating expenses 222,461
 13,867
 14,042
Add HEP segment operating expenses 137,605
 123,984
 105,554
Add (subtract) corporate, other and eliminations (72,507) (28,736) 148
Operating expenses (exclusive of depreciation and amortization) $1,294,234
 $1,018,839
 $1,060,373

Table of Content

Item 8.Financial Statements and Supplementary Data

Item 8.Financial Statements and Supplementary Data



MANAGEMENT'S REPORT ON ITS ASSESSMENT OF THE COMPANY'S INTERNAL CONTROL OVER FINANCIAL REPORTING


Management of HollyFrontier Corporation (the “Company”) 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.


On February 1, 2017, we completed the acquisition of Petro-Canada Lubricants Inc. (“PCLI”). We are in the process of integrating operations of PCLI and affiliated entities related to this acquired business (“PCLI business”), including internal controls over financial reporting and, therefore, management's evaluation and conclusion as to the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K excludes any evaluation of the internal control over financial reporting of the PCLI business. The PCLI business accounted for 12% of the Company's total assets and 8% of total revenues of the Company as of and for the year ended December 31, 2017.

Management assessed the Company's internal control over financial reporting as of December 31, 20172020 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 concludes that, as of December 31, 2017,2020, the Company maintained effective internal control over financial reporting.


The Company's independent registered public accounting firm has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2017.2020. That report appears on page 55.is included herein.





63

REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Stockholders and the Board of Directors of HollyFrontier Corporation




Opinion on Internal Control over Financial Reporting


We have audited HollyFrontier Corporation’s internal control over financial reporting as of December 31, 2017,2020, based on criteria established in Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, HollyFrontier Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2020, based on the COSO criteria.

As indicated in the accompanying Management’s Report on its Assessment of the Company’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 the PCLI business acquired on February 1, 2017, which is included in the 2017 consolidated financial statements of the Company and constituted 12% of total assets as of December 31, 2017 and 8% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of the PCLI business.


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 Company as of December 31, 20172020 and 2016,2019, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2017,2020, and the related notes of the Company and our report dated February 21, 201824, 2021 expressed an unqualified opinion thereon.


Basis for Opinion


The Company’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 Company’s Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’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 Company 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/ Ernst & Young LLP




Dallas, Texas
February 21, 201824, 2021





64

Index to Consolidated Financial Statements


Page Reference
Page Reference
Report of Independent Registered Public Accounting Firm
5766
Consolidated Balance Sheets at December 31, 20172020 and 2016
2019
5869
Consolidated Statements of Income for the years ended December 31, 2017, 20162020, 2019 and 2015
2018
5970
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 20162020, 2019 and 2015
2018
6071
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 20162020, 2019 and 2015
2018
6172
Consolidated Statements of Equity for the years ended December 31, 2017, 20162020, 2019 and 2015
2018
6273
Notes to Consolidated Financial Statements
6373









65

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Stockholders and the Board of Directors of HollyFrontier Corporation


Opinion on the Financial Statements


We have audited the accompanying consolidated balance sheets of HollyFrontier Corporation (the Company) as of December 31, 20172020 and 2016,2019, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2017,2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, 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 Company's internal control over financial reporting as of December 31, 2017,2020, 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, 201824, 2021 expressed an unqualified opinion thereon.


Adoption of ASU No. 2016-02 (Topic 842)

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for leases in 2019 to reflect the accounting method change due to the adoption of ASU 2016-02, Leases (Topic 842).

Basis for Opinion


These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’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 Company 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 consolidated 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.


66

Valuation of Goodwill
Description of the MatterAt December 31, 2020, the Company’s goodwill was $2,294 million, including goodwill assigned to the Refining, Lubricants and Specialty Products, and HEP segments of $1,733 million, $248 million, and $313 million, respectively. As described in Note 1 and Note 11 of the financial statements, goodwill is tested for impairment at least annually on July 1 at the reporting unit level or more frequently if events or changes in circumstances indicate the asset might be impaired. During the fourth quarter of 2020, the Company performed interim goodwill impairment testing of the Sonneborn reporting unit included in the Lubricants and Specialty Products segment, resulting in an impairment charge of $82 million on this reporting unit.
Auditing management’s goodwill impairment tests was complex and highly judgmental for the Company’s Sonneborn and El Dorado Refinery reporting units due to the significant estimation required to determine the fair value of these reporting units. In particular, the fair value estimates were sensitive to significant assumptions, such as revenue growth rates, gross margins, and discount rates, which are affected by expectations about future market or economic conditions. These assumptions have a significant effect on the fair value estimates.
How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company's goodwill impairment testing process. For example, we tested controls over management's review of the significant inputs and assumptions used in determining the reporting unit fair values.
To test the estimated fair value of the Company’s Sonneborn and El Dorado Refinery reporting units, we performed audit procedures with the support of a valuation specialist that included, among others, assessing methodologies and testing the significant assumptions discussed above and the underlying data used by the Company in its analysis. We compared the significant assumptions used by management to relevant industry and economic trends, published forward prices, third party analyst reports, historical operating results and other relevant factors. We performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting units that would result from changes in the assumptions. We also tested management’s reconciliation of the fair value of the reporting units to the market capitalization of the Company.
Environmental Liabilities
Description of the MatterAt December 31, 2020, the Company’s accrual for environmental liabilities was $115 million, of which $94 million was classified as other long-term liabilities. As described in Note 1 and Note 12 of the consolidated financial statements, these accruals include remediation and monitoring costs expected to be incurred over an extended period of time. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated.
Auditing management’s estimates for environmental liabilities was challenging and highly judgmental due to the significant judgment required to develop assumptions related to future costs expected for the remediation of environmental obligations. In particular, the liability estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities.
How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s accrued environmental liability cost estimate and review process.
To test management’s accrued environmental liabilities, we performed audit procedures that included, among others, obtaining a rollforward of the environmental liabilities reflecting activity in the accruals for the past year, performing a look back analysis comparing the prior year short-term accrual estimates to actual current year expenditures, and comparing actual expenditures made to supporting invoices and cash payments. We also utilized an environmental specialist to assist in our evaluation of certain environmental site accruals, including the testing of a sample of cost estimates by inspecting relevant supporting documentation and performing a search of publicly filed records with environmental agencies to test the completeness of environmental liabilities.

67

Impairment of Long-Lived Assets
Description of the MatterAs described in Note 11 of the financial statements, the Company recognized long-lived asset impairment charges of $204.7 million during the second quarter of 2020 related to property, plant, and equipment and other long-lived assets associated with the PCLI asset group. The Company evaluates long-lived assets for impairment by first identifying whether indicators of impairment exist. If indicators are present for an asset group, the Company evaluates recoverability by comparing the estimated future undiscounted cash flows to the carrying amount of the asset group. If the asset group's carrying amount exceeds its estimated future undiscounted cash flows, the fair value of the asset group is then estimated by management and compared to its carrying amount. An impairment charge is recognized on a long-lived asset group when the carrying amount exceeds fair value.
Auditing management’s evaluation of long-lived asset impairment at PCLI involved a high degree of subjectivity and auditor judgment due to the estimation required to assess significant assumptions utilized in estimating the fair value of the asset group based on a discounted cash flow model, such as assumptions related to revenue growth rates, gross margins, and the discount rate. These assumptions have a significant effect on the fair value estimates.
How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s long-lived asset impairment evaluation process, including controls over management’s review of significant assumptions used.
To test the Company’s long-lived asset impairment evaluation process, we performed audit procedures that included, among others, assessing the methodologies used, evaluating the significant assumptions discussed above and testing the completeness and accuracy of the underlying data used by the Company in its analysis. We compared the significant assumptions used by management to relevant industry and economic trends, external market data, historical operating results, and other relevant factors. We also performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the asset group that would result from changes in the underlying assumptions. We involved our valuation specialists to assist in our evaluation of certain significant assumptions used on the calculation of fair value estimates including the fair value of real and personal property and the discount rate.

/s/ Ernst & Young LLP



We have served as the Company’sCompany's auditor since 1977.


Dallas, Texas
February 21, 201824, 2021

68


Table of Content

HOLLYFRONTIER CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
December 31,
20202019
ASSETS
Current assets:
Cash and cash equivalents (HEP: $21,990 and $13,287, respectively)
$1,368,318 $885,162 
Accounts receivable: Product and transportation (HEP: $14,543 and $18,732, respectively)
590,526 834,771 
Crude oil resales39,510 44,914 
630,036 879,685 
Inventories: Crude oil and refined products965,858 1,282,789 
Materials, supplies and other (HEP: $895 and $833, respectively)
207,618 191,413 
1,173,476 1,474,202 
Income taxes receivable91,348 5,478 
Prepayments and other (HEP: $8,591 and $6,795, respectively)
47,583 61,662 
Total current assets3,310,761 3,306,189 
Properties, plants and equipment, at cost (HEP: $2,119,295 and $2,047,674, respectively)
7,299,517 7,237,297 
Less accumulated depreciation (HEP: $(644,149) and $(552,786)), respectively)
(2,726,378)(2,414,585)
4,573,139 4,822,712 
Operating lease right-of-use assets (HEP: $2,979 and $2,652, respectively)
350,548 467,109 
Other assets: Turnaround costs314,816 521,278 
Goodwill (HEP: $312,873 and $312,873, respectively)
2,293,935 2,373,907 
Intangibles and other (HEP: $365,773 and $319,569, respectively)
663,665 673,646 
3,272,416 3,568,831 
Total assets$11,506,864 $12,164,841 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $28,565 and $18,050, respectively)
$1,000,959 $1,215,555 
Income taxes payable1,801 27,965 
Operating lease liabilities (HEP $3,827 and $3,608, respectively)
97,937 104,415 
Accrued liabilities (HEP: $29,518 and $30,418, respectively)
274,459 337,993 
Total current liabilities1,375,156 1,685,928 
Long-term debt (HEP: $1,405,603 and $1,462,031, respectively)
3,142,718 2,455,640 
Noncurrent operating lease liabilities (HEP $68,454 and $72,000, respectively)
285,785 364,420 
Deferred income taxes (HEP: $449 and $424, respectively)
713,703 889,270 
Other long-term liabilities (HEP: $55,105 and $59,021, respectively)
267,299 260,157 
Commitments and contingencies (Note 19)00
Equity:
HollyFrontier stockholders’ equity:
Preferred stock, $1.00 par value – 5,000,000 shares authorized; NaN issued0 0 
Common stock $0.01 par value – 320,000,000 shares authorized; 256,046,051 and 256,042,554 shares issued as of December 31, 2020 and December 31, 20192,560 2,560 
Additional capital4,207,672 4,204,547 
Retained earnings3,913,179 4,744,120 
Accumulated other comprehensive income13,462 14,774 
Common stock held in treasury, at cost - 93,632,391 and 94,196,029 shares as of December 31, 2020 and December 31, 2019, respectively(2,968,512)(2,987,808)
Total HollyFrontier stockholders’ equity5,168,361 5,978,193 
Noncontrolling interest553,842 531,233 
Total equity5,722,203 6,509,426 
Total liabilities and equity$11,506,864 $12,164,841 
 December 31,
 2017 2016
ASSETS   
Current assets:   
Cash and cash equivalents (HEP: $7,776 and $3,657, respectively)
$630,757
 $710,579
Marketable securities—
 424,148
Total cash, cash equivalents and short-term marketable securities630,757
 1,134,727
Accounts receivable: Product and transportation (HEP: $12,803 and $7,846, respectively)
659,530
 449,036
Crude oil resales61,203
 30,163
 720,733
 479,199
Inventories: Crude oil and refined products1,409,538
 970,361
Materials, supplies and other (HEP: $916 and $1,402, respectively)
220,554
 165,315
 1,630,092
 1,135,676
Income taxes receivable44,337
 68,371
Prepayments and other (HEP: $1,395 and $1,486, respectively)
36,909
 33,036
Total current assets3,062,828
 2,851,009
    
Properties, plants and equipment, at cost (HEP: $2,011,915 and $1,702,703, respectively)
6,523,789
 5,546,856
Less accumulated depreciation (HEP: $(408,599) and $(337,135), respectively)
(1,810,515) (1,538,408)
 4,713,274
 4,008,448
Other assets: Turnaround costs231,319
 217,340
Goodwill (HEP: $310,610 and $288,991, respectively)
2,244,744
 2,022,463
Intangibles and other (HEP: $206,167 and $208,975, respectively)
439,989
 336,401
 2,916,052
 2,576,204
Total assets$10,692,154
 $9,435,661
    
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable (HEP: $14,637 and $10,518, respectively)
$1,220,795
 $935,387
Income taxes payable3,159
 —
Accrued liabilities (HEP: $33,214 and $37,793, respectively)
198,756
 147,842
Total current liabilities1,422,710
 1,083,229
    
Long-term debt (HEP: $1,507,308 and $1,243,912, respectively)
2,498,993
 2,235,137
Deferred income taxes (HEP: $525 and $509, respectively)
647,785
 620,414
Other long-term liabilities (HEP: $62,590 and $62,971, respectively)
225,726
 194,896
    
Equity:   
HollyFrontier stockholders’ equity:   
Preferred stock, $1.00 par value – 5,000,000 shares authorized; none issued—
 —
Common stock $.01 par value – 320,000,000 shares authorized; 256,015,550 and 255,962,866 shares issued as of December 31, 2017 and December 31, 20162,560
 2,560
Additional capital4,132,696
 4,026,805
Retained earnings3,346,615
 2,776,728
Accumulated other comprehensive income29,869
 10,612
Common stock held in treasury, at cost – 78,607,928 and 78,617,600 shares as of December 31, 2017 and December 31, 2016, respectively(2,140,911) (2,135,311)
Total HollyFrontier stockholders’ equity5,370,829
 4,681,394
Noncontrolling interest526,111
 620,591
Total equity5,896,940
 5,301,985
Total liabilities and equity$10,692,154
 $9,435,661


Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 20172020 and 2016.2019. HEP is a variable interest entity.


See accompanying notes.
69
Table of Content

HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
 
 Years Ended December 31,
 202020192018
Sales and other revenues$11,183,643 $17,486,578 $17,714,666 
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization):
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment)9,158,805 13,918,384 13,940,782 
Lower of cost or market inventory valuation adjustment78,499 (119,775)136,305 
9,237,304 13,798,609 14,077,087 
Operating expenses (exclusive of depreciation and amortization)1,300,277 1,394,052 1,285,838 
Selling, general and administrative expenses (exclusive of depreciation and amortization)313,600 354,236 290,424 
Depreciation and amortization520,912 509,925 437,324 
Goodwill and long-lived asset impairments545,293 152,712 0 
Total operating costs and expenses11,917,386 16,209,534 16,090,673 
Income (loss) from operations(733,743)1,277,044 1,623,993 
Other income (expense):
Earnings of equity method investments6,647 5,180 5,825 
Interest income7,633 22,139 16,892 
Interest expense(126,527)(143,321)(131,363)
Gain on business interruption insurance settlement81,000 0 0 
Gain on sales-type leases33,834 0 0 
Loss on early extinguishment of debt(25,915)0 0 
Gain on foreign currency transactions2,201 5,449 6,197 
Other, net7,824 5,013 2,923 
(13,303)(105,540)(99,526)
Income (loss) before income taxes(747,046)1,171,504 1,524,467 
Income tax expense (benefit):
Current(55,420)220,486 270,274 
Deferred(176,727)78,666 76,969 
(232,147)299,152 347,243 
Net income (loss)(514,899)872,352 1,177,224 
Less net income attributable to noncontrolling interest86,549 99,964 79,264 
Net income (loss) attributable to HollyFrontier stockholders$(601,448)$772,388 $1,097,960 
Earnings (loss) per share:
Basic$(3.72)$4.64 $6.25 
Diluted$(3.72)$4.61 $6.19 
Average number of common shares outstanding:
Basic161,983 166,287 175,009 
Diluted161,983 167,385 176,661 
  Years Ended December 31,
  2017 2016 2015
       
Sales and other revenues $14,251,299
 $10,535,700
 $13,237,920
Operating costs and expenses:      
Cost of products sold (exclusive of depreciation and amortization):      
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment) 11,467,799
 8,765,927
 10,239,218
Lower of cost or market inventory valuation adjustment (108,685) (291,938) 226,979
  11,359,114
 8,473,989
 10,466,197
Operating expenses (exclusive of depreciation and amortization) 1,294,234
 1,018,839
 1,060,373
Selling, general and administrative expenses (exclusive of depreciation and amortization) 264,874
 125,648
 120,846
Depreciation and amortization 409,937
 363,027
 346,151
Goodwill and asset impairment 19,247
 654,084
 —
Total operating costs and expenses 13,347,406
 10,635,587
 11,993,567
Income (loss) from operations 903,893
 (99,887) 1,244,353
Other income (expense):      
Earnings (loss) of equity method investments 12,510
 14,213
 (3,738)
Interest income 3,736
 2,491
 3,391
Interest expense (117,597) (72,192) (43,470)
Loss on early extinguishment of debt (12,225) (8,718) (1,370)
Gain (loss) on foreign currency swap 24,545
 (6,520) —
Gain on foreign currency transactions 16,921
 —
 —
Remeasurement gain on HEP pipeline interest acquisitions 36,254
 —
 —
Other, net 826
 (921) 9,402
  (35,030) (71,647) (35,785)
Income (loss) before income taxes 868,863
 (171,534) 1,208,568
Income tax expense (benefit):      
Current 125,143
 (79,181) 552,196
Deferred (137,522) 98,592
 (146,136)
  (12,379) 19,411
 406,060
Net income (loss) 881,242
 (190,945) 802,508
Less net income attributable to noncontrolling interest 75,847
 69,508
 62,407
Net income (loss) attributable to HollyFrontier stockholders $805,395
 $(260,453) $740,101
Earnings (loss) per share attributable to HollyFrontier stockholders:      
Basic $4.54
 $(1.48) $3.91
Diluted $4.52
 $(1.48) $3.90
Average number of common shares outstanding:      
Basic 176,174
 176,101
 188,731
Diluted 177,196
 176,101
 188,940


See accompanying notes.
70
Table of Content

HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
 
 Years Ended December 31,
 202020192018
Net income (loss)$(514,899)$872,352 $1,177,224 
Other comprehensive income (loss):
Foreign currency translation adjustment6,226 13,337 (38,227)
Hedging instruments:
Change in fair value of cash flow hedging instruments(7,475)14,364 5,166 
Reclassification adjustments to net income (loss) on settlement of cash flow hedging instruments2,604 (19,713)6,055 
Net unrealized gain (loss) on hedging instruments(4,871)(5,349)11,221 
Pension and other post-retirement benefit obligations:
Actuarial gain (loss) on pension plans1,862 (990)(923)
Pension plans gain reclassified to net income (loss)(422)0 0 
Actuarial gain (loss) on post-retirement healthcare plans(1,129)(2,412)2,612 
Post-retirement healthcare plans gain reclassified to net income (loss)(3,564)(3,587)(3,481)
Actuarial gain (loss) on retirement restoration plan(230)(224)258 
Retirement restoration plan loss reclassified to net income (loss)22 6 27 
Net change in pension and other post-retirement benefit obligations(3,461)(7,207)(1,507)
Other comprehensive income (loss) before income taxes(2,106)781 (28,513)
Income tax benefit(794)(370)(5,585)
Other comprehensive income (loss)(1,312)1,151 (22,928)
Total comprehensive income (loss)(516,211)873,503 1,154,296 
Less noncontrolling interest in comprehensive income86,549 99,964 79,264 
Comprehensive income (loss) attributable to HollyFrontier stockholders$(602,760)$773,539 $1,075,032 
  Years Ended December 31,
  2017 2016 2015
       
Net income (loss) $881,242
 $(190,945) $802,508
Other comprehensive income (loss):      
Foreign currency translation adjustment 22,151
 —
 —
Securities available-for-sale:      
Unrealized gain (loss) on marketable securities (4) 81
 29
Reclassification adjustments to net income on sale or maturity of marketable securities —
 23
 9
Net unrealized gain (loss) on marketable securities (4) 104
 38
Hedging instruments:      
Change in fair value of cash flow hedging instruments 2,919
 (17,625) (5,847)
Reclassification adjustments to net income on settlement of cash flow hedging instruments 10,448
 41,585
 (47,492)
Amortization of unrealized loss attributable to discontinued cash flow hedges 1,080
 1,080
 1,080
Net unrealized gain (loss) on hedging instruments 14,447
 25,040
 (52,259)
Other post-retirement benefit obligations:      
Actuarial loss on pension plans (1,162) —
 —
Actuarial gain (loss) on post-retirement healthcare plans (1,058) 2,363
 3,278
Post-retirement healthcare plans gain reclassified to net income (3,481) (3,482) (3,299)
Actuarial gain (loss) on retirement restoration plan (123) (9) 80
Retirement restoration plan loss reclassified to net income 17
 15
 20
Net change in other post-retirement benefit obligations (5,807) (1,113) 79
Other comprehensive income (loss) before income taxes 30,787
 24,031
 (52,142)
Income tax expense (benefit) 11,349
 9,322
 (20,237)
Other comprehensive income (loss) 19,438
 14,709
 (31,905)
Total comprehensive income (loss) 900,680
 (176,236) 770,603
Less noncontrolling interest in comprehensive income (loss) 75,790
 69,450
 62,551
Comprehensive income (loss) attributable to HollyFrontier stockholders $824,890
 $(245,686) $708,052


See accompanying notes.




71
Table of Content

HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
 202020192018
Cash flows from operating activities:
Net income (loss)$(514,899)$872,352 $1,177,224 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization520,912 509,925 437,324 
Goodwill and long-lived asset impairments545,293 152,712 0 
Lower of cost or market inventory valuation adjustment78,499 (119,775)136,305 
Earnings of equity method investments, inclusive of distributions1,084 (213)(149)
Loss on early extinguishment of debt25,915 0 0 
Gain on sales-type leases(33,834)0 0 
(Gain) loss on sale of assets(201)50 2,171 
Deferred income taxes(176,727)78,666 76,969 
Equity-based compensation expense31,654 42,269 42,172 
Change in fair value – derivative instruments26,456 36,888 (31,515)
(Increase) decrease in current assets:
Accounts receivable254,684 (150,437)35,793 
Inventories230,142 91,599 136,551 
Income taxes receivable(85,442)32,368 7,752 
Prepayments and other(2,541)3,633 (10,340)
Increase (decrease) in current liabilities:
Accounts payable(241,765)312,794 (326,030)
Income taxes payable(25,897)9,048 15,281 
Accrued liabilities(85,708)13,748 53,281 
Turnaround expenditures(94,692)(318,415)(217,228)
Other, net4,998 (18,601)18,855 
Net cash provided by operating activities457,931 1,548,611 1,554,416 
Cash flows from investing activities:
Additions to properties, plants and equipment(270,877)(263,651)(256,888)
Additions to properties, plants and equipment – HEP(59,283)(30,112)(54,141)
Acquisitions, net of cash acquired0 (662,665)(54,179)
Investment in equity company - HEP(2,438)(17,886)0 
Proceeds from sale of assets1,554 194 3,100 
Other, net882 1,206 1,588 
Net cash used for investing activities(330,162)(972,914)(360,520)
Cash flows from financing activities:
Borrowings under credit agreements258,500 365,500 337,000 
Repayments under credit agreements(310,500)(323,000)(426,000)
Proceeds from issuance of senior notes – HFC748,925 0 0 
Proceeds from issuance of senior notes – HEP500,000 0 0 
Redemption of senior notes - HEP(522,500)0 0 
Purchase of treasury stock(7,642)(533,083)(363,437)
Dividends(229,493)(225,170)(233,544)
Distributions to noncontrolling interest(89,001)(132,268)(125,653)
Proceeds of financing arrangements0 0 32,547 
Proceeds from issuance of common units - HEP0 0 114,759 
Contribution from noncontrolling interests23,899 3,210 0 
Payments on finance leases(2,995)(1,551)0 
Deferred financing costs(15,538)0 0 
Other, net(429)(1,893)0 
Net cash provided by (used for) financing activities353,226 (848,255)(664,328)
Effect of exchange rate on cash flow2,161 2,968 (5,573)
Cash and cash equivalents:
Increase (decrease) for the period483,156 (269,590)523,995 
Beginning of period885,162 1,154,752 630,757 
End of period$1,368,318 $885,162 $1,154,752 
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest$(120,257)$(133,809)$(130,106)
Income taxes, net$(54,256)$(178,967)$(252,644)
Accrued and unpaid capital expenditures$73,867 $19,752 $28,066 
  Years Ended December 31,
  2017 2016 2015
Cash flows from operating activities:      
Net income (loss) $881,242
 $(190,945) $802,508
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation and amortization 409,937
 363,027
 346,151
Goodwill and asset impairment 19,247
 654,084
 —
Lower of cost or market inventory valuation adjustment (108,685) (291,938) 226,979
Earnings of equity method investments, inclusive of distributions 1,450
 961
 8,613
Loss (gain) on early extinguishment of debt attributable to unamortized discount / premium 2,475
 8,718
 (3,788)
Remeasurement gain on pipeline interest acquisitions (36,254) —
 —
Loss (gain) on sale of assets 508
 (72) (8,677)
Deferred income taxes (137,522) 98,592
 (146,136)
Equity-based compensation expense 42,337
 25,561
 30,367
Change in fair value – derivative instruments (4,265) (12,155) 38,525
Excess tax expense from equity-based compensation —
 (4,209) —
(Increase) decrease in current assets:      
Accounts receivable (115,322) (127,221) 238,392
Inventories (162,297) (1,869) (33,717)
Income taxes receivable 50,601
 (68,371) 11,719
Prepayments and other (6,753) 16,555
 13,291
Increase (decrease) in current liabilities:      
Accounts payable 188,975
 247,603
 (406,339)
Income taxes payable (18,525) (8,142) (11,500)
Accrued liabilities 57,227
 16,142
 (6,924)
Turnaround expenditures (135,104) (125,254) (89,365)
Other, net 22,118
 5,881
 (24,231)
Net cash provided by operating activities 951,390
 606,948
 985,868
Cash flows from investing activities:      
Additions to properties, plants and equipment (227,449) (372,195) (483,034)
Additions to properties, plants and equipment – HEP (44,810) (107,595) (193,121)
Purchase of PCLI, net of cash acquired (870,627) —
 —
Purchase of pipeline interests - HEP (245,446) (42,627) (55,032)
Proceeds from sale of assets 1,377
 849
 19,264
Purchases of marketable securities (41,565) (546,632) (509,338)
Sales and maturities of marketable securities 465,716
 266,603
 839,513
Other, net 3,134
 —
 —
Net cash used for investing activities (959,670) (801,597) (381,748)
Cash flows from financing activities:      
Borrowings under credit agreements 995,000
 869,000
 973,900
Repayments under credit agreements (536,000) (1,028,000) (832,900)
Proceeds from issuance of senior notes – HFC —
 992,550
 —
Proceeds from issuance of senior notes – HEP 101,750
 394,000
 —
Proceeds from issuance of term loan - HFC —
 350,000
 —
Repayment of term loan - HFC —
 (350,000) —
Redemption of senior notes - HFC —
 —
 (155,156)
Redemption of senior notes - HEP (309,750) —
 —
Repayment of financing obligation —
 (39,500) —
Proceeds from issuance of common units - HEP 52,110
 125,870
 —
Purchase of treasury stock —
 (133,430) (742,823)
Shares withheld for tax withholding obligations (15,926) (4,677) (6,242)
Dividends (235,508) (234,004) (246,908)
Distributions to noncontrolling interest (110,351) (92,607) (83,268)
Other, net (13,955) (10,507) (12,175)
Net cash provided by (used for) financing activities (72,630) 838,695
 (1,105,572)
Effect of exchange rate on cash flow 1,088
 —
 —
Cash and cash equivalents:      
Increase (decrease) for the period (79,822) 644,046
 (501,452)
Beginning of period 710,579
 66,533
 567,985
End of period $630,757
 $710,579
 $66,533
Supplemental disclosure of cash flow information:      
Cash paid during the period for:      
Interest $(124,375) $(54,074) $(46,442)
Income taxes, net $(93,272) $(40,236) $(586,447)


See accompanying notes.
72
Table of Content



HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
HollyFrontier Stockholders' Equity
Common StockAdditional CapitalRetained EarningsAccumulated Other Comprehensive IncomeTreasury StockNon-controlling InterestTotal Equity
Balance at December 31, 2017$2,560 $4,132,696 $3,346,615 $29,869 $(2,140,911)$526,111 $5,896,940 
Net income— — 1,097,960 — — 79,264 1,177,224 
Dividends ($1.32 declared per common share)— — (233,544)— — — (233,544)
Distributions to noncontrolling interest holders— — — — — (125,653)(125,653)
Other comprehensive loss, net of tax— — — (22,928)— — (22,928)
Equity attributable to HEP common unit issuances, net of tax— 42,199 — — — 58,134 100,333 
Issuance of common stock under incentive compensation plans, net of forfeitures— (17,742)— — 17,742 — — 
Equity-based compensation— 38,972 — — — 3,200 42,172 
Purchase of treasury stock— — — — (367,470)— (367,470)
Purchase of HEP units for restricted grants— — — — — (568)(568)
Adoption of accounting standards
— — (14,129)6,682 — — (7,447)
Balance at December 31, 2018$2,560 $4,196,125 $4,196,902 $13,623 $(2,490,639)$540,488 $6,459,059 
Net income— — 772,388 — — 99,964 872,352 
Dividends ($1.34 declared per common share)— — (225,170)— — — (225,170)
Distributions to noncontrolling interest holders— — — — — (132,268)(132,268)
Other comprehensive income, net of tax— — — 1,151 — — 1,151 
Equity attributable to HEP common unit issuances, net of tax— — — — — (139)(139)
Issuance of common stock under incentive compensation plans, net of forfeitures— (31,314)— — 31,314 — — 
Equity-based compensation— 39,736 — — — 2,533 42,269 
Purchase of treasury stock— — — — (528,483)— (528,483)
Purchase of HEP units for restricted grants— — — — — (1,893)(1,893)
Contributions from noncontrolling interests— — — — — 22,548 22,548 
Balance at December 31, 2019$2,560 $4,204,547 $4,744,120 $14,774 $(2,987,808)$531,233 $6,509,426 
Net income (loss)— — (601,448)— — 86,549 (514,899)
Dividends ($1.40 declared per common share)— — (229,493)— — — (229,493)
Distributions to noncontrolling interest holders— — — — — (89,001)(89,001)
Other comprehensive loss, net of tax— — — (1,312)— — (1,312)
Issuance of common stock under incentive compensation plans— (26,938)— — 26,938 — — 
Equity-based compensation— 29,460 — — — 2,194 31,654 
Purchase of treasury stock— — — — (7,642)— (7,642)
Purchase of HEP units for restricted grants— — — — — (1,032)(1,032)
Contributions from noncontrolling interests— — — — — 23,899 23,899 
Other— 603 — — — — 603 
Balance at December 31, 2020$2,560 $4,207,672 $3,913,179 $13,462 $(2,968,512)$553,842 $5,722,203 
 HollyFrontier Stockholders' Equity    
 Common Stock Additional Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Treasury Stock Non-controlling Interest Total Equity
Balance at December 31, 2014$2,560
 $4,003,628
 $2,778,577
 $27,894
 $(1,289,075) $577,135
 $6,100,719
Net income—
 —
 740,101
 —
 —
 62,407
 802,508
Dividends—
 —
 (247,489) —
 —
 —
 (247,489)
Distributions to noncontrolling interest holders—
 —
 —
 —
 —
 (83,268) (83,268)
Other comprehensive income (loss), net of tax—
 —
 —
 (32,049) —
 144
 (31,905)
Issuance of common stock under incentive compensation plans, net of forfeitures—
 (14,958) —
 —
 14,958
 —
 —
Equity-based compensation, inclusive of tax expense—
 22,382
 —
 —
 —
 3,483
 25,865
Purchase of treasury stock—
 —
 —
 —
 (753,114) —
 (753,114)
Purchase of HEP units for restricted grants—
 —
 —
 —
 —
 (3,555) (3,555)
Other—
 —
 —
 —
 —
 12
 12
Balance at December 31, 2015$2,560
 $4,011,052
 $3,271,189
 $(4,155) $(2,027,231) $556,358
 $5,809,773
Net income (loss)—
 —
 (260,453) —
 —
 69,508
 (190,945)
Dividends—
 —
 (234,008) —
 —
 —
 (234,008)
Distributions to noncontrolling interest holders—
 —
 —
 —
 —
 (92,607) (92,607)
Other comprehensive income (loss), net of tax—
 —
 —
 14,767
 —
 (58) 14,709
Equity attributable to HEP common unit issuances, net of tax—
 23,110
 —
 —
 —
 88,166
 111,276
Issuance of common stock under incentive compensation plans, net of forfeitures—
 (25,982) —
 —
 25,982
 —
 —
Equity-based compensation, inclusive of tax expense—
 18,625
 —
 —
 —
 2,727
 21,352
Purchase of treasury stock—
 —
 —
 —
 (134,062) —
 (134,062)
Purchase of HEP units for restricted grants—
 —
 —
 —
 —
 (3,521) (3,521)
Other—
 —
 —
 —
 —
 18
 18
Balance at December 31, 2016$2,560
 $4,026,805
 $2,776,728
 $10,612
 $(2,135,311) $620,591
 $5,301,985
Net income—
 —
 805,395
 —
 —
 75,847
 881,242
Dividends—
 —
 (235,508) —
 —
 —
 (235,508)
Distributions to noncontrolling interest holders—
 —
 —
 —
 —
 (110,351) (110,351)
Other comprehensive income (loss), net of tax—
 —
 —
 19,495
 —
 (57) 19,438
Equity attributable to HEP common unit issuances, net of tax—
 69,802
 —
 (238) —
 (61,390) 8,174
Equity awards issued in PCLI acquisition—
 6,600
 —
 —
 —
 —
 6,600
Issuance of common stock under incentive compensation plans, net of forfeitures—
 (10,326) —
 —
 10,326
 —
 —
Equity-based compensation—
 39,815
 —
 —
 —
 2,522
 42,337
Purchase of treasury stock—
 —
 —
 —
 (15,926) —
 (15,926)
Purchase of HEP units for restricted grants—
 —
 —
 —
 —
 (605) (605)
Other—
 —
 —
 —
 —
 (446) (446)
Balance at December 31, 2017$2,560
 $4,132,696
 $3,346,615
 $29,869
 $(2,140,911) $526,111
 $5,896,940


See accompanying notes.









Table of Content
73


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

Description of Business: References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In these financial statements, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person, with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. These financial statements contain certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.


We are principally an independent petroleum refiner and marketer that produces high-value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products and specialty and modified asphalt. We own and operate petroleum refineries that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States. In addition, we ownproduce base oils and operate a lubricant production facilityother specialized lubricants in the United States, Canada and the Netherlands, with retail and wholesale marketing of itsour products through a global sales network with locations in Canada, the United States, Europe, China and China. Latin America.

As of December 31, 2017,2020, we:


•owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two2 refinery facilities located in Tulsa, Oklahoma (collectively, the “Tulsa Refineries”), a refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”) and a refinery in Woods Cross, Utah (the “Woods Cross Refinery”);
•owned a facility in Cheyenne, Wyoming, which operated as a petroleum refinery until early August 2020, at which time its assets began to be converted to renewable diesel production (the “Cheyenne Refinery”);
•owned and operated Petro-Canada Lubricants Inc. (“PCLI”) located in Mississauga, Ontario, which produces base oils and other specializedspecialty lubricant products;
•owned and operated Sonneborn (as defined below) with manufacturing facilities in Petrolia, Pennsylvania and the Netherlands, which produce specialty lubricant products, such as white oils, petrolatums and waxes;
•owned and operated Red Giant Oil Company LLC (“Red Giant Oil”), which supplies locomotive engine oil and has storage and distribution facilities in Iowa and Wyoming, along with a blending and packaging facility in Texas;
•owned and operated HollyFrontier Asphalt Company LLC (“HFC Asphalt”), which operates various asphalt terminals in Arizona, New Mexico and Oklahoma; and
•owned a 59%57% limited partner interest and a non-economic general partner interest in HEP, a variable interest entity (“VIE”). HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and refinery processing units that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States.

In the third quarter of 2020, we permanently ceased petroleum refining operations at our Cheyenne Refinery and subsequently began converting certain assets at our Cheyenne Refinery to renewable diesel production. This decision was primarily based on a positive outlook in the market for renewable diesel and the expectation that future free cash flow generation at our Cheyenne Refinery would be challenged due to lower gross margins resulting from the economic impact of the COVID-19 pandemic and compressed crude differentials due to dislocations in the crude oil market. Additional factors included uncompetitive operating and maintenance costs forecasted for our Cheyenne Refinery and the anticipated loss of the Environmental Protection Agency’s (“EPA”) small refinery exemption.

74

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


During the second quarter of 2020, we recorded long-lived asset impairment charges of $232.2 million related to our Cheyenne Refinery asset group. In connection with the cessation of petroleum refining operations at our Cheyenne Refinery, we recognized $24.7 million in decommissioning expense for the year ended December 31, 2020. In addition, for the year ended December 31, 2020, we recorded a reserve of $9.0 million against our repair and maintenance supplies inventory and $3.8 million in employee severance costs related to the conversion of our Cheyenne Refinery to renewable diesel production. These decommissioning, inventory reserve and severance costs were recognized in operating expenses, of which $24.8 million was recorded in our Refining segment and $12.7 million was recorded in our Corporate and Other segment.

During the second quarter of 2020, we also initiated and completed a corporate restructuring. As a result of this restructuring, we recorded $3.7 million in employee severance costs, which were recognized primarily as operating expenses in our Refining segment and selling, general and administrative expenses in our Corporate and Other segment.

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc.,November 12, 2018, we entered into a sharean equity purchase agreement with Suncor Energy Inc. (“Suncor”) to acquire 100% of the issued and outstanding capital stock of PCLI.Sonneborn US Holdings Inc. and 100% of the membership rights in Sonneborn Coöperatief U.A. (collectively, “Sonneborn”). The acquisition closed on February 1, 2017. 2019.

On July 10, 2018, we entered into a definitive agreement to acquire Red Giant Oil, a privately-owned lubricants company. The acquisition closed on August 1, 2018.

See Note 2 for additional information.information on these acquisitions.


Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we 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.


Variable Interest Entities: HEP is a VIE as defined under U.S. generally accepted accounting principles (“GAAP”). A VIE is a legal entity whose equity owners do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly impact the entity's financial performance, the obligation to absorb the entity's expected losses or rights to expected residual returns. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP's financial performance, and therefore as HEP's primary beneficiary, we consolidate HEP.


In 2019, HEP Cushing LLC, a wholly-owned subsidiary of HEP, 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. Cushing Connect Pipeline & Terminal LLC and its two subsidiaries, Cushing Connect Pipeline and Cushing Connect Terminal, are each VIE’s because they do not have sufficient equity at risk to finance their activities without additional financial support. HEP is the primary beneficiary of two of these entities as HEP is constructing and will operate the Cushing Connect Pipeline, and HEP has more ability to direct the activities that most significantly impact the financial performance of Cushing Connect Pipeline & Terminal LLC and Cushing Connect Pipeline. Therefore, HEP consolidates these two entities. HEP is not the primary beneficiary of Cushing Connect Terminal, which HEP accounts for using the equity method of accounting.

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 Equivalents: We consider all highly liquid instruments with a maturity of three months or less at the date of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are primarily invested in highly-rated instruments issued by government or municipal entities with strong credit standings.



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Marketable Securities: We consider all marketable debt securities with maturities greater than three months at the date of purchase to be marketable securities. Our marketable securities consist of commercial paper, corporate debt securities and government and municipal debt securities with the maximum maturity or put date of any individual issue generally not more than two years, while the maximum duration of the portfolio of investments is not greater than one year. These instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income.

Balance Sheet Offsetting: We purchase and sell inventories of crude oil with certain same-parties that are net settled in accordance with contractual net settlement provisions. Our policy is to present such balances on a net basis becausesince it more appropriately presents our economic resources (accounts receivable)accounts receivables and claims against us (accounts payable) and the future cash flows associatedpayables consistent with such assets and liabilities.our contractual settlement provisions.


75

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Accounts Receivable: Our accounts receivable consist of amounts due from customers that are primarily companies in the petroleum industry. Credit is extended based on our evaluation of the customer's financial condition, and in certain circumstances collateral, such as letters of credit or guarantees, is required. We reserve for doubtful accounts based on our historical loss experience as well as specific accounts identified as high risk, which historically have been minimal.expected credit losses from current economic conditions and management’s expectations of
future economic conditions. Credit losses are charged to the allowance for doubtful accounts when an account is deemed uncollectible. Our allowance for doubtful accounts was $3.6 million and $2.3$3.4 million at December 31, 20172020 and 2016, respectively.$4.5 million at December 31, 2019.


Accounts receivable attributable to crude oil resales generally represent the sell sidesale of excess crude oil sales to other purchasers and / or users in cases when our crude oil supplies are in excess of our immediate needs as well as certain reciprocal buy / sell exchanges of crude oil. At times we enter into such buy / sell exchanges to facilitate the delivery of quantities to certain locations. In many cases, we enter into net settlement agreements relating to the buy / sell arrangements, which may mitigate credit risk.


Inventories: Inventories related to our refining operations are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil and unfinished and finished refined products, or market. Cost, consisting of raw material, transportation and conversion costs, is determined using the LIFO inventory valuation methodology and market is determined using current replacement costs. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. An actual valuation of inventory under the LIFO method is made at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management'smanagement’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.


Inventories of our Petro-Canada Lubricants businessand Sonneborn businesses are stated at the lower of cost, using the first-in, first-out (“FIFO”) method, or net realizable value.


Inventories consisting of process chemicals, materials and maintenance supplies and RINsrenewable identification numbers (“RINs”) are stated at the lower of weighted-average cost or net realizable value.


Leases: Effective January 1, 2019, we adopted Accounting Standards Update (“ASU”) 2016-02, “Leases” (Topic 842). At inception, we determine if an arrangement is or contains a lease. Right-of-use (“ROU”) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our payment obligation under the leasing arrangement. ROU 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, plants and equipment and accrued liabilities and other long-term liabilities on our consolidated balance sheet.

Our lease term includes an option to extend the lease when it is reasonably certain that we will exercise that option. Leases with a term of 12 months or less are not recorded on our balance sheet. For certain equipment leases, we apply a portfolio approach for the operating lease ROU assets and liabilities. Also, 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. In addition, HEP, as a lessor, does not separate the non-lease (service) component in contracts in which the lease component is the dominant component. HEP treats these combined components as an operating lease.

Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in our consolidated balance sheets and are measured at fair value. Changes in the derivative instrument's fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 1314 for additional information.


76

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Properties, plantsPlants and equipment:Equipment: Properties, plants and equipment are stated at cost. Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 15 to 32 years for refining, pipeline and terminal facilities, 10 to 40 years for buildings and improvements, 5 to 30 years for other fixed assets and 5 years for vehicles.



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Asset Retirement Obligations: We record legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and / or the normal operation of long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded as a liability with the associated retirement costs capitalized as part of the asset's carrying amount in the period in which it is incurred and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability's fair value. Certain of our refining assets have no recorded liability for asset retirement obligations since the timing of any retirement and related costs are currently indeterminable.


Our asset retirement obligations were $24.8$42.6 million and $22.1$35.9 million at December 31, 20172020 and 2016,2019, respectively, which are included in “Other long-term liabilities” in our consolidated balance sheets. Accretion expense was insignificant for the years ended December 31, 2017, 20162020, 2019 and 2015.2018.


Intangibles, Goodwill and long-lived assets:Long-lived Assets: Intangible assets are assets (other than financial assets) that lack physical substance, and goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired and liabilities assumed. Goodwill acquired in a business combination and intangibles with indefinite useful lives are not amortized, whereas intangible assets with finite useful lives are amortizedon a straight-line basis. Goodwill and intangible assets that are not subject to amortization are tested for impairment annually or more frequently if eventsan event occurs or changes in circumstances indicatechange that would more likely than not reduce the asset might be impaired.fair value of a reporting unit below its carrying amount. Our goodwill impairment testing first entails either a comparisonquantitative assessment or an optional qualitative assessment to determine whether it is more likely than not that the fair value of oura reporting unit fair values relative to their respectiveis less than its carrying values.amount. If we determine that based on the qualitative factors that it is more likely than not that the carrying value exceedsamount of the reporting unit is greater than its fair value, fora quantitative test is performed in which we estimate the fair value of the related reporting unit. If the carrying amount of a reporting unit exceeds its fair value, the goodwill of that reporting unit is impaired, and we measure goodwill impairment as the excess of the carrying amount of the reporting unit goodwill over the impliedrelated fair valuevalue. The carrying amount of that goodwill based on estimates of the fair value of allour intangible assets and liabilities ingoodwill may fluctuate from period to period due to the reporting unit.effects of foreign currency translation adjustments on goodwill and intangible assets assigned to our Lubricants and Specialty Products segment.


OurFor purposes of long-lived asset impairment evaluation, we have grouped our long-lived assets principally consist ofas follows: (i) our refiningrefinery asset groups, which include certain HEP logistics assets, that are organized as refining(ii) our Lubricants and Specialty Products asset groups and (iii) our lubricants and specialty products business. TheHEP asset groups, which comprises HEP assets not included in our refinery asset groups. These asset groups also constitute our individual refinery reporting units that are usedrepresent the lowest level for testing and measuring goodwill impairments.which independent cash flows can be identified. Our long-lived assets are evaluated for 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 measured, if any, is equal to the amount by which the asset group’s carrying value exceeds its fair value.


See Note 1011 for additional information regarding our goodwill and long-lived assetassets including impairment charges recorded during the years ended December 31, 20172020 and 2016.2019.


Upon our acquisition of PCLI, we recognized intangibles, including trademarks, patents, technical know-how and customer relationships, totaling $102.1 million that are being amortized on a straight-line basis over periods ranging from 10 to 20 years. At December 31, 2017, the balance of these intangibles was $100.0 million, and is presented net of accumulated amortization of $5.9 million in “Intangibles and other” in our consolidated balance sheets.

Our consolidated HEP assets include intangible assets consisting of third-party transportation agreements and customer relationships. These intangible assets are amortized on a straight-line basis over periods ranging from 10 to 30 years. Amortization expense was $2.6 million and $2.0 million for the years ended December 31, 2017 and 2016, respectively, and expected to approximate $8.0 million annually over the next five years. The balances of these intangible assets were $95.2 million and $36.5 million at December 31, 2017, and 2016, respectively, and are presented net of accumulated amortization of $26.3 million and $23.7 million, respectively, in “Intangibles and other” in our consolidated balance sheets.

Investments in Joint Ventures:Equity Method Investments: We consolidate the financial and operating results of joint ventures in which we have an ownership interest of greater than 50% or a controlling interest with respect to VIE’s, and use the equity method of accountingaccount for investments in which we have a noncontrolling interest, yet have significant influence over the entity. Underentity, using the equity method of accounting, whereby we record our pro-rata share of earnings and contributions to and distributions from joint ventures as adjustments to our investment balance.

HEP has a 50% interest in Osage Pipe Line Company, LLC, the owner of a pipeline running from Cushing, Oklahoma to El Dorado, Kansas (the “Osage Pipeline”) and a 50% interest in Cheyenne Pipeline, LLC, the owner of a pipeline running from Fort Laramie, Wyoming to Cheyenne, Wyoming (the “Cheyenne Pipeline”), that are accounted. HEP also accounts for Cushing Connect Terminal, a subsidiary of the Cushing Connect Pipeline & Terminal LLC joint venture, using the equity method of accounting.accounting, as HEP does not have the ability to direct the activities that most significantly impact the entity. As of December 31, 2017,2020, HEP's underlying equity and recorded investment balances in the joint ventures are $39.3$93.2 million and $85.3 $120.5 million respectively. The differences are being amortized as adjustments to HEP's pro-rata share of earnings in the joint ventures.



77

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



Revenue Recognition: Refined Revenues on refined product sales and related cost ofexcess crude oil sales are recognized when products are shippeddelivered (via pipeline, in-tank or rack) and the customer obtains control of such inventory, which is typically when title has passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines.passes and the customer is billed. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling costs incurred are reported inas cost of products sold.


Our Petro-Canada Lubricantslubricants and specialty products business has sales agreements with marketers and distributors that provide certain rights of return or provisions for the repurchase of products previously sold to them. Under these agreements, with Canadian marketers, revenues and cost of revenues are deferred until the products have been sold to end customers,customers. Our lubricants and specialty products business also has agreements that create an obligation to deliver products at a future date for sales to U.S. distributors, revenues arewhich consideration has already been received and recorded as deferred revenue. This revenue is recognized when the products are delivered to the customer.

HEP recognizes revenues as products are shipped through its pipelines and terminals and as other services are rendered. Additionally, HEP has certain throughput agreements that specify minimum volume requirements, whereby HEP bills 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, HEP recognizes these deficiency payments as revenue. In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the distributors, netend of allowances for returns thatthe contractual shortfall make-up period. HEP recognizes the service portion of these deficiency payments as revenue when HEP does not expect it will be required to satisfy these performance obligations in the future based on the pattern of rights exercised by the customer. Payment terms under our contracts with customers are expected to be repurchased fromconsistent with industry norms and are typically payable within 30 days of the distributors. In both cases, repurchased products are subsequently sold directly to end customers.date of invoice.


Cost Classifications: Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as cost of products sold. Additionally, we enter into buy / sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at cost. Operating expenses include direct costs of labor, maintenance materials and services, utilities marketing expense and other direct operating costs. Selling, general and administrative expenses include compensation, professional services and other support costs.


Deferred Maintenance Costs: Our refinery units require regular major maintenance and repairs which are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require regular “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred. Deferred turnaround and catalyst amortization expense was $112.9$158.4 million, $110.6$141.9 million and $107.8$110.9 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.


Environmental Costs: Environmental costs are charged to operating expenses if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. We have ongoing investigations of environmental matters at various locations and routinely assess our recorded environmental obligations, if any, with respect to such matters. 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 are undiscounted and 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. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.


Contingencies: We 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 matters as well as potential ranges of probable losses. We accrue for contingencies when it is probable that a loss has occurred and when the amount of that loss is reasonably estimable. A determination of the amount of reserves required, if any, for these 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 matters.


78

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Foreign Currency Translation: The functional currency of PCLI Assets and its affiliated non-U.S. Petro-Canada Lubricants entities includes the Canadian dollar, the euro and Chinese renminbi. Balance sheet accountsliabilities recorded in foreign currencies are translated into U.S. dollars using exchange rates in effect as of the balance sheet date. Revenue and expense accounts are translated using the weighted-average exchange rates during the period presented. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income.


In connection with our PCLI acquisition, on February 1, 2017, we issued intercompany notes to initially fund certain of our foreign businesses. Remeasurement adjustments resulting from the conversion of such intercompany financing amounts to functional currencies are recorded as gains and losses as a component of other income (expense) in the income statement. Such adjustments are not recorded to the Lubricants and Specialty Products segment operations, but to corporateCorporate and other.Other. See Note 20 for additional information on our segments.



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Income Taxes: Provisions for income taxes include deferred taxes resulting from temporary differences in income for financial and tax purposes, using the liability method of accounting for income taxes. The liability method requires the effect of tax rate changes on deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.


Potential interest and penalties related to income tax matters are recognized in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.


Inventory Repurchase Obligations:We periodically enter into same-party sell / buy transactions, whereby we sell certain refined product inventory and subsequently repurchase the inventory in order to facilitate delivery to certain locations. Such sell / buy transactions are accounted for as inventory repurchase obligations under which proceeds received under the initial sell is recognized as an inventory repurchase obligationobligations that isare subsequently reversed when the inventory isinventories are repurchased. For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, we received proceeds of $47.4$44.9 million, $57.0$52.1 million and $115.4$51.2 million and subsequently repaid $49.8$46.4 million, $58.0$49.2 million and $115.3$52.5 million, respectively, under these sell / buy transactions.


New Accounting Pronouncements - Recently Adopted


HedgeIncome Tax Accounting
In August 2017, Accounting Standard Update (“ASU”) 2017-12, “Derivatives and Hedging: Targeted Improvements toDecember 2019, ASU 2019-12, “Simplifying the Accounting for Hedging Activities,Income Taxes,” was issued amending hedge accounting recognitionwhich eliminates some exceptions to the general approach in ASC Topic 740 “Income Taxes” and presentationalso provides clarification of other aspects of ASC 740. We adopted this standard effective January 1, 2020 on a prospective basis, and it did not have a material affect on our financial condition, results of operations or cash flows for the periods presented.

Fair Value Measurements
In August 2018, ASU 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement,” was issued which removed, modified and added certain disclosures for fair value measurements. We adopted this standard effective January 1, 2020, and it did not affect our financial condition, results of operations or cash flows.

Defined Benefit Plans
In August 2018, ASU 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans,” was issued which removed disclosure requirements including eliminationfor (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year and (ii) the effects of a one-percentage-point change in assumed health care cost trend rates on the aggregate of the requirementservice and interest cost components of net periodic benefit costs and the benefit obligation for postretirement health care benefits. Additionally, a new disclosure required under this standard is an explanation of the reasons for significant gains and losses related to separately measure and report hedge ineffectiveness, and eases certain documentation and assessment requirements. Thischanges in the benefit obligation for the period. We adopted this standard has an effective date of January 1, 2019. We do not expectDecember 31, 2020 with the updated disclosures in Note 18. The adoption of this standard to have a materialhad no impact on our financial condition, results of operations or cash flows.


Post-retirement Benefit Cost
79

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Credit Losses Measurement
In March 2017,June 2016, ASU 2017-07, “Improving the Presentation2016-13, “Measurement of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost,Credit Losses on Financial Instruments,” was issued amendingrequiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current GAAP related to the income statement presentation of the components of net periodic post-retirement cost (credit). This standard has an effective date of January 1, 2018. We do not expect adoption of this standard to have a material impact on our financial condition, results of operations or cash flows.

Share-Based Compensation
In March 2016, ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeituresconditions and statutory tax withholding requirements, as well as classification in the statement of cash flows.reasonable and supportable forecasts. We adopted this standard effective January 1, 2017 on2020, at which time our review of historic and expected credit losses resulted in a prospective basis with the excess tax expense from stock-based compensation recognized as a discrete itemdecrease of $3.2 million in our provisionreserve for income taxes. Excess tax expensedoubtful accounts. Based upon our assessment of the potential impact of current and forecasted conditions, we increased our reserve for doubtful accounts by $2.1 million during the the year ended December 31, 2017 totaled $0.7 million. The new standard also requires2020. Assumptions about the potential effects of the COVID-19 pandemic on our estimate of expected credit losses are inherently subjective and difficult to forecast. However, we believe that employee taxes paid when an employer withholds sharesour current estimate of allowance 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 $15.9 million, $4.7 million and $6.2 million, respectively. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.

Leases
In February 2016, ASU 2016-02, “Leases,” was issued requiring leasesdoubtful accounts to be measuredreasonable based upon current information 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, andforecasts.


NOTE 2:Acquisitions

Sonneborn
On November 12, 2018, we are evaluating the impact of this standard. In preparing for adoption, we have identified, reviewed and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired software and are implementing systems to facilitate lease capture and related accounting treatment.


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Inventories Measurement
In July 2015, ASU 2015-11, “Inventory - Simplifying the Measurement of Inventory,” was issued requiring measurement of inventories, other than inventories accounted for using the LIFO method, to be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business less reasonable, predictable cost of completion, disposal and transportation. We adopted this standard effective January 1, 2017 for our affected inventories, which is primarily the inventory of our Petro-Canada Lubricants business that is valued on a FIFO basis. Adoption had no material effect on our financial condition, results of operations or cash flows.

Revenue Recognition
In May 2014, ASU 2014-09, “Revenue from Contracts with Customers” was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard has an effective date of January 1, 2018, and we anticipate 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.


NOTE 2:PCLI Acquisition

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a sharean equity purchase agreement with Suncor to acquire100% of the outstanding capital stock of PCLI.Sonneborn. The acquisition closed on February 1, 2017. Cash2019. Aggregate consideration totaled $701.6 million and consisted of $662.7 million in cash paid was $862.1 million, or $1.125 billion in Canadian dollars. PCLI is located in Mississauga, Ontario, Canada andat acquisition, net of cash acquired. Sonneborn is a producer of lubricant productsspecialty hydrocarbon chemicals such as base oils, white oils, specialty productspetrolatums and finished lubricants. The operations of our Petro-Canada Lubricants business also include marketing of these products to both retail and wholesale outlets through a global sales networkwaxes with locationsmanufacturing facilities in Canada, the United States Europe and China.Europe.

Aggregate consideration totaled $906.7 million and consists of $862.1 million in cash paid to Suncor at acquisition, a closing date working capital settlement of $30.6 million that was paid to Suncor in the second quarter of 2017, an accrued payable in the amount of $7.4 million, and $6.6 million representing a portion of the fair value of replacement restricted stock unit awards issued to PCLI employees that relate to pre-acquisition services.


This transaction iswas accounted for as a business combination using the acquisition method of accounting, with the purchase price allocated to the fair value of the acquired PCLISonneborn assets and liabilities as of the February 1, 2019 acquisition date, with the excess purchase price recorded as goodwill. This goodwill was assigned to our Lubricants and Specialty Products segment and is not deductible for income tax purposes.

Fair values were as follows: cash and cash equivalents $38.9 million, current assets $139.4 million, properties, plants and equipment $168.2 million, goodwill $282.3 million, intangibles and other noncurrent assets $231.5 million, current liabilities $47.9 million and deferred income tax and other long-term liabilities $110.8 million.

Intangibles included customer relationships, trademarks, patents and technical know-how totaling $214.6 million that are being amortized on a straight-line basis over a 12-year period.

Our consolidated financial and operating results reflect the Sonneborn operations beginning February 1, 2019. Our results of operations include revenue and income before income taxes of $340.3 million and $5.1 million, respectively, for the period from February 1, 2019 through December 31, 2019 related to these operations.

The following unaudited pro forma information for the years ended December 31, 2019 and 2018 presents the revenues and operating income for our Lubricants and Specialty Products segment assuming the acquisition of Sonneborn had occurred as of January 1, 2018. The proforma effects on consolidated HFC revenue and operating income are not material.
Years Ended December 31,
20192018
(In thousands)
Sales and other revenues$2,124,778 $2,195,690 
Operating income (1)
$(116,254)$99,371 
(1) The year ended December 31, 2019, includes goodwill impairment of $152.7 million from the PCLI reporting unit of our Lubricants and Specialty Products segment. See Note 11 for additional information on this goodwill impairment.

Red Giant Oil
On July 10, 2018, we entered into a definitive agreement to acquire Red Giant Oil, a privately-owned lubricants company. The acquisition closed on August 1, 2018. Cash consideration paid was $54.2 million. Red Giant Oil is one of the largest suppliers of locomotive engine oil in North America and is headquartered in Council Bluffs, Iowa.

80

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

This transaction was accounted for as a business combination using the acquisition method of accounting, with the purchase price allocated to the fair value of the acquired Red Giant Oil assets and liabilities as of the August 1 acquisition date, with the excess purchase price recorded as goodwill assigned to our Lubricants and Specialty Products segment. This goodwill is not deductible for income tax purposes. Fair values were as follows: current assets $14.4 million, properties and equipment $21.3 million, intangible assets $9.7 million, goodwill $10.8 million and current liabilities $2.0 million.


The following summarizes the PCLI value of assetsWe incurred $2.0 million, $24.2 million and liabilities acquired on February 1, 2017:
 (in millions)
Cash and cash equivalents$21.6
Accounts receivable and other current assets118.5
Inventories214.9
Properties, plants and equipment438.0
Goodwill194.8
Intangibles, precious metals and other noncurrent assets124.3
Accounts payable and accrued liabilities(87.4)
Deferred income tax liabilities(105.4)
Other long-term liabilities(12.6)
Net assets acquired$906.7


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Our consolidated financial and operating results reflect the operations of our Petro-Canada Lubricants business beginning February 1, 2017. Our results of operations$3.6 million, for the yearyears ended December 31, 2017 included revenues2020, 2019 and income before income taxes of $1,125.3 million and $71.8 million,2018, respectively, related to these operations.

As of December 31, 2017, we have incurred $27.9 million in incremental direct acquisitionintegration and integrationregulatory costs that principally relate to legal, advisory, regulatory and other professional fees and are presented as selling, general and administrative expenses.




NOTE 3:Leases

Lessee

We have operating and finance leases for land, buildings, pipelines, storage tanks, transportation and other equipment for our operations. Our leases have remaining terms of one to 59 years, some of which include options to extend the leases for up to 10 years. Certain of our leases for pipeline assets include provisions for variable payments which are based on a measure of throughput and also contain a provision for the lessor to adjust the rate per barrel periodically over the life of the lease. These variable costs are not included in the initial measurement of ROU assets and lease liabilities.

The following table presents the amounts and balance sheet locations of our operating and financing leases recorded on our consolidated balance sheets.
December 31,
20202019
(In thousands)
Operating leases:
Operating lease right-of-use assets$350,548 $467,109 
Operating lease liabilities97,937 104,415 
Noncurrent operating lease liabilities285,785 364,420 
Total operating lease liabilities$383,722 $468,835 
Finance leases:
Properties, plants and equipment, at cost$24,321 $13,406 
Accumulated amortization(5,713)(6,233)
Properties, plants and equipment, net$18,608 $7,173 
Accrued liabilities
$1,916 $1,567 
Other long-term liabilities
5,097 5,163 
Total finance lease liabilities$7,013 $6,730 

81

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Supplemental balance sheet information related to our leases was as follows:
December 31,
20202019
Weighted average remaining lease term (in years)
Operating leases7.27.2
Finance leases3.38.1
Weighted average discount rate
Operating leases4.1 %4.0 %
Finance leases5.3 %5.2 %

The components of lease expense were as follows:
Years Ended December 31,
20202019
(In thousands)
Operating lease expense$121,608 $112,770 
Finance lease expense:
Amortization of right-of-use assets4,400 1,543 
Interest on lease liabilities415 334 
Variable lease cost3,580 4,449 
Total lease expense$130,003 $119,096 

Supplemental cash flow information related to leases was as follows:
Years Ended December 31,
20202019
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$126,313 $116,980 
Operating cash flows from finance leases$415 $334 
Financing cash flows from finance leases$2,995 $1,551 
Right-of-use assets obtained in exchange for lease obligations:
Operating leases$18,823 $121,750 
    Finance leases$4,085 $2,096 

82

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

As of December 31, 2020, minimum future lease payments of our operating and finance lease obligations were as follows:
OperatingFinance
(In thousands)
2021$109,756 $2,220 
202291,172 1,651 
202375,878 1,686 
202451,859 1,209 
202512,871 746 
2025 and thereafter116,502 349 
Future minimum lease payments458,038 7,861 
   Less: imputed interest74,316 848 
Total lease obligations383,722 7,013 
   Less: current obligations97,937 1,916 
Long-term lease obligations$285,785 $5,097 

As of December 31, 2020, we have entered into certain leases that have not yet commenced. Such leases include a 2-year lease for petroleum tank storage, with estimated future lease payments of $2.6 million, expected to commence in the first quarter of 2021.

Lessor

Our consolidated statements of income reflect lease revenue recognized by HEP for contracts with third parties in which HEP is the lessor.

Substantially all of the assets supporting contracts meeting the definition of a lease have long useful lives, and HEP believes these assets will continue to have value when the current agreements expire due to HEP's risk management strategy for protecting the residual fair value of the underlying assets by performing ongoing maintenance during the lease term.

One of HEP’s throughput agreements with Delek US Holdings, Inc. (“Delek”) was partially renewed during the year ended December 31, 2020. Certain components of this agreement met the criteria of sales-type leases since the underlying assets are not expected to have an alternative use at the end of the lease term to anyone other than Delek. 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. Therefore, HEP recognized a gain on sales-type leases totaling $33.8 million during the year ended December 31, 2020. This sales-type lease transaction, including the related gain, was a non-cash transaction.

83

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Lease income recognized was as follows:
Years Ended December 31,
20202019
(In thousands)
Operating lease revenues$22,636 $33,242 
Gain on sales-type leases$33,834 $0 
Sales-type lease interest income$1,928 $0 
Lease revenues relating to variable lease payments not included in measurement of the sales-type lease receivable$1,690 $0 

For HEP’s sales-type leases, HEP included customer obligations related to minimum volume requirements in guaranteed minimum lease payments. Portions of HEP’s 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. HEP 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 payments in which HEP is a lessor to third-party contracts as of December 31, 2020 were as follows:
OperatingSales-type
(In thousands)
2021$11,586 $2,955 
20229,128 2,955 
20239,000 2,955 
20249,000 2,955 
20252,512 2,955 
Thereafter0 27,335 
Total lease payment receipts$41,226 42,110 
Less: imputed interest(32,262)
9,848 
Unguaranteed residual assets at end of leases25,182 
   Net investment in leases$35,030 

Net investment in sales-type leases recorded on our consolidated balance sheet was composed of the following:
December 31, 2020
(In thousands)
Lease receivables$26,045 
Unguaranteed residual assets8,985 
  Net investment in leases$35,030 


NOTE 3:Holly Energy Partners

NOTE 4:Holly Energy Partners

HEP is a publicly held master limited partnership that owns and operates logistic assets consisting of petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and refinery processing units that principally support our refining and marketing operations, as well as other third-party refineries, in the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States and Delek’s refinery in Big Spring, Texas.States. Additionally, as of December 31, 2020, HEP ownsowned a 75% interest in UNEV Pipeline, LLC (“UNEV”), the owner of a pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”) and associated product terminals, and a 50% ownership interest in each of Osage Pipe Line Company, LLC, the Osageowner of a pipeline running from Cushing, Oklahoma to El Dorado, Kansas (the “Osage Pipeline”); Cheyenne Pipeline, LLC, the owner of a pipeline running from Fort Laramie, Wyoming to Cheyenne, Wyoming (the “Cheyenne Pipeline”) and Cushing Connect Pipeline & Terminal LLC (“Cushing Connect”), the Cheyenne Pipeline.owner of a crude oil storage terminal in Cushing, Oklahoma and a pipeline under construction that will run from Cushing, Oklahoma to our Tulsa Refineries.

84

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


At December 31, 2017,2020, we owned a 59%57% limited partner interest and a non-economic general partner interest in HEP. As the general partner of HEP, we have the sole ability to direct the activities that most significantly impact HEP's financial performance, and therefore as HEP's primary beneficiary, we consolidate HEP.


HEP has two2 primary customers (including us) and generates revenues by charging tariffs for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and by storing and providing other services at its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed further below), we accounted for 83%80% of HEP’s total revenues for the year ended December 31, 2017.2020. We do not provide financial or equity support through any liquidity arrangements and / or debt guarantees to HEP.


HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes. HEP’s creditors have no recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. See Note 1213 for a description of HEP’s debt obligations.


HEP has risk associated with its operations. If a major customer of HEP were to terminate its contracts or fail to meet desired shipping or throughput levels for an extended period of time, revenue would be reduced and HEP could suffer substantial losses to the extent that a new customer is not found. In the event that HEP incurs a loss, our operating results will reflect HEP’s loss, net of intercompany eliminations, to the extent of our ownership interest in HEP at that point in time.


SLC Pipeline and Frontier PipelineCushing Connect Joint Venture
OnIn October 31, 2017,2019, HEP acquired the remaining 75% interest in SLC PipelineCushing LLC the owner of a pipeline that serves refineries in the Salt Lake City, Utah area (the “SLC Pipeline”(“HEP Cushing”), a wholly-owned subsidiary of HEP, and the remaining 50% interest in Frontier Aspen LLC, the owner of a pipeline running from Wyoming to Frontier Station, Utah (the “Frontier Pipeline”Plains Marketing, L.P. (“PMLP”), from subsidiariesa wholly-owned subsidiary of Plains All American Pipeline, L.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect, for cash consideration(i) the development, construction, ownership and operation of $250.0 million.

These acquisitions were accounted for as a business combination achievednew 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that will connect the Cushing, Oklahoma crude oil hub to our Tulsa Refineries and (ii) the ownership and operation of 1.5 million barrels of crude oil storage in stages. HEP’s preexisting equity method investmentsCushing, Oklahoma (the “Cushing Connect Terminal”). The Cushing Connect Terminal was fully in SLC Pipeline and Frontier Aspen were remeasured at an acquisition date fair value of $112.0 million, since HEP acquired a controlling interest, and a gain was recognized on the remeasurement of $36.3 million. The fair value of HEP's preexisting equity method investmentsservice beginning in SLC Pipeline and Frontier Aspen was estimated using Level 3 inputs under the income method for these entities, adjusted for lack of control and marketability.

The total consideration of $362.0 million, consisting of cash consideration of $250.0 millionApril 2020, and the fair value of HEP's preexisting equity method investmentsCushing Connect Pipeline is expected to be placed in SLC Pipeline and Frontier Aspen of $112.0 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 fair values are preliminary, and therefore, may change once all needed information has become available and valuations are complete.

Woods Cross Assets
On October 3, 2016, HEP acquired from us all the membership interests of Woods Cross Operating LLC, which owns the crude unit, FCCU and polymerization unit of the first phase of our Woods Cross Refinery expansion project that was completed inservice during the second quarter of 2016, for cash consideration of approximately $278.0 million.

In connection with this transaction, we2021. Long-term commercial agreements have been entered into 15-year tolling agreements containing minimum quarterly throughput commitments that provide minimum annualized payments to support the Cushing Connect assets.

Cushing Connect will contract with an affiliate of HEP of $56.7 million.


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Cheyenne Pipeline
On June 3, 2016, HEP acquired a 50% interest in Cheyenne Pipeline LLC, ownerto manage the construction and operation of the CheyenneCushing Connect Pipeline in exchange for a contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline will continue to be operated byand with an affiliate of Plains which ownsto manage the remaining 50% interest.operation of the Cushing Connect Terminal. The 87-mile crude oil pipeline runs from Fort Laramie, Wyoming to Cheyenne, Wyomingtotal investment in Cushing Connect will be shared proportionately among the partners, and has an 80,000 BPD capacity.

Tulsa Tanks
On March 31, 2016, HEP acquired crude oil tanks located at our Tulsa Refineries from Plains for $39.5 million. Previously in 2009, we sold these tanks toestimates its share of the cost of the Cushing Connect Terminal contributed by Plains and leased them back, and due to our continuing interest in the tanks, we accounted for the transaction as a financing arrangement. Accordingly, the tanks remained on our balance sheet and were depreciated for accounting purposes, and the proceeds received from Plains were recorded as a financing obligation and presented as a component of outstanding debt.

In accounting for HEP’s March 2016 purchase from Plains, the amount paid was recorded against our outstanding financing obligation balance of $30.8 million, with the excess $8.7 million resulting in a loss on early extinguishment of debt.

Magellan Asset Exchange
On February 22, 2016, we obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in exchange for a 20-year terminalling services agreement, whereby, a subsidiary of Magellan Midstream Partners (“Magellan Midstream”) will provide terminalling services for all of our products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Under the agreement, we will be charged tariffs based on the volumes of refined product processed. Osage is the ownerCushing Connect Pipeline construction costs are approximately $65.0 million. However, any Cushing Connect Pipeline construction costs exceeding 10% of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to our El Dorado Refinery in Kansas and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. This exchange was accounted for at fair value, whereby the 50% membership interest in the Osage Pipeline was recorded at fair value and an offsetting residual deferred credit in the amount of $38.9 million was recorded, which will be amortized to cost of products sold over the 20-year service period. No gain or loss was recorded for this exchange.budget are borne solely by HEP.

Also on February 22, 2016, we contributed the 50% membership interest in Osage to HEP, and in exchange received HEP's El Paso terminal. Pursuant to this exchange, HEP agreed to build two connections to Magellan Midstream's El Paso terminal. In addition, HEP agreed to become the operator of the Osage Pipeline. This exchange was accounted for at carry-over basis with no resulting gain or loss.

El Dorado Asset Transaction
On November 1, 2015, HEP acquired from us newly constructed naphtha fractionation and hydrogen generation units at our 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 that provide minimum annualized payments to HEP of $15.1 million.

Frontier Pipeline Transaction
On August 31, 2015, HEP purchased a 50% interest in Frontier Aspen LLC (previously known as Frontier Pipeline Company), owner of the Frontier Pipeline, from an affiliate of Enbridge, Inc. for $55.0 million. The 289-mile crude oil pipeline runs from Casper, Wyoming to Frontier Station, Utah, has a 72,000 BPD capacity and supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline. As noted above, HEP acquired the remaining 50% interest on October 31, 2017.


Transportation Agreements
HEP serves our refineries under long-term pipeline, terminal and tankage throughput agreements and refinery processing tolling agreements expiring from 2020 2021 through 2036. UnderUnder these agreements, we pay HEP fees to transport, store and process throughput volumes of refined products, crude oil and feedstocks on HEP's pipelines, terminals, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index or Federal Energy Regulatory Commission index. As of December 31, 2017,2020, these agreements result inrequired minimum annualized payments to HEP of $351.1 million. However, subsequent to year end, these agreements were modified to account for the conversion of our Cheyenne Refinery to renewable diesel production, and as of January 1, 2021, require minimum annualized payments to HEP of $324.5$341.9 million.


Our transactions with HEP and fees paid under our transportation agreements with HEP and UNEV are eliminated and have no impact on our consolidated financial statements.


85

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued




Incentive Distribution Rights Simplification Agreement
On October 31, 2017, we closed on an equity restructuring transaction with HEP pursuant to which our incentive distribution rights were canceled and our 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we received 37,250,000 HEP common units. In addition, we 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 were eligible to receive distributions as consideration.


HEP Private Placement Agreements
On January 25, 2018, HEP entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 HEP common units, representing limited partner interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, at which time HEP received proceeds of approximately $110.0 million, which were used to repay indebtedness under the HEP Credit Agreement. After this common unit issuance, our limited partner interest in HEP is 57%.

On October 3, 2016, HEP closed on a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,420,000 HEP common units, representing limited partnership interests, at a price of $30.18 per common unit. HEP received proceeds of approximately $103.0 million, which were used to finance a portion of the Woods Cross assets acquisition. In connection with this private placement and to maintain our then economic 2% general partner interest in HEP, we made capital contributions totaling $2.1 million to HEP in October 2016.


HEP Common Unit Continuous Offering Program
OnIn May 10, 2016, HEP established a continuous offering program under 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. During the year ended December 31, 2017,2020, HEP did not issue any common units under this program. As of December 31, 2020, HEP has issued 1,538,4522,413,153 common units under this program, providing $52.1$82.3 million in netgross proceeds. In connection with this program and to maintain our then economic 2% general partner interest in HEP, we made capital contributions totaling $1.1 million during the year ended December 31, 2017. As of December 31, 2017, HEP has issued 2,241,907 common units with an aggregate gross sales amount of $77.1 million.

HEP intends to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. Amounts repaid under HEP’s credit facility may be reborrowed from time to time.


As a result of these transactions and resulting HEP ownership changes, we adjusted additional capital and equity attributable to HEP's noncontrolling interest holders to reallocate HEP's equity among its unitholders.




NOTE 5:Revenues

Substantially all revenue-generating activities relate to sales of refined product and excess crude oil inventories sold at market prices (variable consideration) under contracts with customers. Additionally, we have revenues attributable to HEP logistics services provided under petroleum product and crude oil pipeline transportation, processing, storage and terminalling agreements with third parties.

Disaggregated revenues were as follows:
Years Ended December 31,
202020192018
(In thousands)
Revenues by type
Refined product revenues
Transportation fuels (1)
$7,825,625 $12,952,899 $13,326,654 
Specialty lubricant products (2)
1,657,344 1,864,450 1,636,859 
Asphalt, fuel oil and other products (3)
672,371 1,025,663 985,234 
Total refined product revenues10,155,340 15,843,012 15,948,747 
Excess crude oil revenues (4)
884,248 1,470,148 1,597,321 
Transportation and logistic services98,039 121,027 108,412 
Other revenues (5)
46,016 52,391 60,186 
Total sales and other revenues$11,183,643 $17,486,578 $17,714,666 

86

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Years Ended December 31,
202020192018
(In thousands)
Refined product revenues by market
United States
Mid-Continent$5,096,268 $8,424,191 $8,427,200 
Southwest2,310,432 3,621,273 3,772,278 
Rocky Mountains1,311,416 2,208,541 2,476,044 
Northeast552,069 578,932 339,407 
Canada616,683 721,169 732,321 
Europe, Asia and Latin America268,472 288,906 201,497 
Total refined product revenues$10,155,340 $15,843,012 $15,948,747 

(1)Transportation fuels consist of gasoline, diesel and jet fuel. For the year ended December 31, 2020, $1.6 million is reported in our Corporate and Other segment.
(2)Specialty lubricant products consist of base oil, waxes, finished lubricants and other specialty fluids.
(3)Asphalt, fuel oil and other products revenue include revenues attributable to our Refining, Lubricants and Specialty Products and Corporate and Other segments of $533.5 million, $135.4 million and $3.5 million respectively, for the year ended December 31, 2020. For the year ended December 31, 2019 such revenues attributable to our Refining and Lubricants and Specialty Products segments were $808.9 million and $216.8 million, respectively, and $822.6 million and $162.6 million, respectively, for the year ended December 31, 2018.
(4)Excess crude oil revenues represent sales of purchased crude oil inventory that at times exceeds the supply needs of our refineries.
(5)Other revenues are principally attributable to our Refining segment.

Our consolidated balance sheets reflect contract liabilities related to unearned revenues attributable to future service obligations under HEP’s third-party transportation agreements and production agreements from the acquisition of Sonneborn on February 1, 2019. The following table presents changes to contract liabilities for the years ended December 31, 2020 and 2019:
Years Ended December 31,
202020192018
(In thousands)
Balance at January 1$4,652 $132 $179 
Sonneborn acquisition0 6,463 0 
Increase28,746 26,751 6,748 
Recognized as revenue(26,660)(28,694)(6,795)
Balance at December 31$6,738 $4,652 $132 

As of December 31, 2020, we have long-term contracts with customers that specify minimum volumes of gasoline, diesel, lubricants and specialty products to be sold ratably at market prices through 2025. Such volumes are typically nominated in the month preceding delivery and delivered ratably throughout the following month. Future prices are subject to market fluctuations and therefore, we have elected the exemption to exclude variable consideration under these contracts under Accounting Standards Codification 606-10-50-14A. Aggregate minimum volumes expected to be sold (future performance obligations) under our long-term product sales contracts with customers are as follows:
202120222023ThereafterTotal
(In thousands)
Refined product sales volumes (barrels)19,318 13,771 12,795 11,698 57,582 
Additionally, HEP has long-term contracts with third-party customers that specify minimum volumes of product to be transported through its pipelines and terminals that result in fixed-minimum annual revenues through 2025. Annual minimum revenues attributable to HEP’s third-party contracts as of December 31, 2020 are presented below:
87

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

202120222023ThereafterTotal
(In thousands)
HEP contractual minimum revenues$22,041 $11,053 $9,000 $11,512 $53,606 

We have 0 customers which had accounted for over 10% of our annual revenues for the years ended December 31, 2020, 2019 or 2018.


NOTE 4:Fair Value Measurements

NOTE 6:Fair Value Measurements

Our financial instruments measured at fair value on a recurring basis consist of investments in marketable securities, derivative instruments and RINs credit obligations.instruments.


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 of derivative instruments at December 31, 2020 and 2019 were as follows:

Carrying AmountFair Value by Input Level
Financial InstrumentLevel 1Level 2Level 3
(In thousands)
December 31, 2020
Assets:
Commodity forward contracts$275 $0 $275 $0 
Total assets$275 $0 $275 $0 
Liabilities:
NYMEX futures contracts$418 $418 $0 $0 
Commodity price swaps359 0 359 0 
Commodity forward contracts196 0 196 0 
Foreign currency forward contracts23,005 0 23,005 0 
Total liabilities$23,978 $418 $23,560 $0 


88

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



Carrying AmountFair Value by Input Level
Financial InstrumentLevel 1Level 2Level 3
(In thousands)
December 31, 2019
Assets:
Commodity price swaps$13,455 $0 $13,455 $0 
Commodity forward contracts4,133 0 4,133 0 
Total assets$17,588 $0 $17,588 $0 
Liabilities:
NYMEX futures contracts$2,578 $2,578 $0 $0 
Commodity price swaps1,230 0 1,230 0 
Commodity forward contracts3,685 0 3,685 0 
Foreign currency forward contracts6,722 0 6,722 0 
Total liabilities$14,215 $2,578 $11,637 $0 
The carrying amounts of marketable securities, derivative instruments and RINs credit obligations at December 31, 2017 and December 31, 2016 were as follows:
    Fair Value by Input Level
Financial Instrument Carrying Amount Level 1 Level 2 Level 3
  (In thousands)
December 31, 2017        
Assets:        
Commodity forward contracts $3,840
 $—
 $3,840
 $—
Total assets $3,840
 $—
 $3,840
 $—
         
Liabilities:        
NYMEX futures contracts $3,360
 $3,360
 $—
 $—
Commodity price swaps 2,424
 —
 2,424
 —
Commodity forward contracts 1,020
 —
 1,020
 —
RINs credit obligations (1)
 8,931
 —
 8,931
 —
Total liabilities $15,735
 $3,360
 $12,375
 $—
    Fair Value by Input Level
Financial Instrument Carrying Amount Level 1 Level 2 Level 3
  (In thousands)
December 31, 2016        
Assets:        
Marketable securities $424,148
 $—
 $424,148
 $—
Commodity price swaps 14,563
 —
 14,358
 205
Commodity forward contracts 5,905
 —
 5,905
 —
HEP interest rate swaps 91
 —
 91
 —
Total assets $444,707
 $—
 $444,502
 $205
         
Liabilities:        
NYMEX futures contracts $1,975
 $1,975
 $—
 $—
Commodity price swaps 26,845
 —
 24,086
 2,759
Commodity forward contracts 8,316
 —
 8,316
 —
Foreign currency forward contracts 6,519
 —
 6,519
 —
Total liabilities $43,655
 $1,975
 $38,921
 $2,759

(1) Represent obligations for RINs credits for which we do not have sufficient quantities at December 31, 2017 to satisfy our Environmental Protection Agency (“EPA”) regulatory blending requirements.


Level 1 Financial Instruments
Our NYMEX futures contracts are exchange traded and are measured and recorded at fair value using quoted market prices, a Level 1 input.


Level 2 Financial Instruments
Investments in marketable securities, derivativeDerivative instruments consisting of foreign currency forward contracts, commodity price swaps and forward sales and purchase contracts and HEP's interest rate swaps are measured and recorded at fair value using Level 2 inputs. The fair valuesvalue of the commodity price and interest rate swap contracts areis based on the net present value of expected future cash flows related to both variable and fixed rate legs of the respective swap agreements. The measurements are computed using market-based observable inputs,input and quoted forward commodity prices with respect to our commodity price swaps andswaps. The fair value of the forward London Interbank Offered Rate (“LIBOR”) yield curve with respect to HEP's interest rate swaps. RINs credit obligationssales and purchase contracts are valued based on current market RINscomputed using quoted forward commodity prices. The fair value of the marketable securities isforeign currency forward contracts are based on values provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input.


Nonrecurring Fair Value Measurements
During the year ended December 31, 2020, we recognized goodwill and long-lived asset impairment charges based on fair value measurements utilized during our goodwill and long-lived asset impairment testing (see Note 11). The fair value measurements were based on a combination of valuation methods including discounted cash flows, the guideline public company and guideline transaction methods and obsolescence adjusted replacement costs, all of which are Level 3 inputs.

During the year ended December 31, 2020, HEP recognized a gain on sales-type leases (see Note 4). 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 were used in determining the net investment in leases and related recognized gain on sales-type leases. The asset valuation estimates included Level 3 inputs based on a replacement cost valuation method.



89

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



Level 3 Financial Instruments
We at times have commodity price swap and forward contracts that relate to forecasted sales and purchases of commodities for which quoted forward market prices are not readily available. The forward rate used to value these price swaps and forward sales and purchase contracts are derived using a projected forward rate using quoted market rates for similar products, adjusted for regional pricing and grade differentials, a Level 3 input.

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to derivative instruments) for the years ended December 31, 2017 and 2016:

  Years Ended December 31,
Level 3 Financial Instruments 2017 2016
 (In thousands)
Liability balance at beginning of period $(2,554) $—
Change in fair value:    
Recognized in other comprehensive income 1,626
 (1,460)
Recognized in cost of products sold (4,664) (1,094)
Settlement date fair value of contractual maturities:    
Recognized in sales and other revenues (165) —
Recognized in cost of products sold 5,757
 —
Liability balance at end of period $—
 $(2,554)


NOTE 5:Earnings Per Share

NOTE 7:Earnings Per Share

Basic earnings per share is calculated as net income (loss) attributable to HollyFrontier stockholders, adjusted for participating securities’ share in earnings divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive,includes the issuance of the net incremental shares resulting from our restricted sharesstock units and performance share units.units if the effect is dilutive. The following is a reconciliation of the denominators of the basic and diluted per share computations for net income (loss) attributable to HollyFrontier stockholders:
 Years Ended December 31,
 202020192018
 (In thousands, except per share data)
Net income (loss) attributable to HollyFrontier stockholders$(601,448)$772,388 $1,097,960 
Participating securities’ share in earnings1,811 1,034 3,714 
Net income (loss) attributable to common shares$(603,259)$771,354 $1,094,246 
Average number of shares of common stock outstanding161,983 166,287 175,009 
Effect of dilutive variable restricted stock units and performance share units (1)
0 1,098 1,652 
Average number of shares of common stock outstanding assuming dilution161,983 167,385 176,661 
Basic earnings (loss) per share$(3.72)$4.64 $6.25 
Diluted earnings (loss) per share$(3.72)$4.61 $6.19 
(1) Excludes anti-dilutive restricted and performance share units of:1,082 302 238 


  Years Ended December 31,
  2017 2016 2015
  (In thousands, except per share data)
Net income (loss) attributable to HollyFrontier stockholders $805,395
 $(260,453) $740,101
Participating securities’ (restricted stock) share in earnings 5,047
 1,003
 2,306
Net income (loss) attributable to common shares $800,348
 $(261,456) $737,795
Average number of shares of common stock outstanding 176,174
 176,101
 188,731
Effect of dilutive variable restricted shares and performance share units (1)
 1,022
 —
 209
Average number of shares of common stock outstanding assuming dilution 177,196
 176,101
 188,940
Basic earnings (loss) per share $4.54
 $(1.48) $3.91
Diluted earnings (loss) per share $4.52
 $(1.48) $3.90
       
(1) Excludes anti-dilutive restricted and performance share units of: 543
 469
 89


NOTE 6:Stock-Based Compensation

NOTE 8:Stock-Based Compensation
As of December 31, 2017, we
We have twoa principal share-based compensation plans (collectively, the “Long-Termplan (the “2020 Long-Term Incentive Compensation Plan”).


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


, which allows us to grant new equity awards until February 12, 2030. We also have a long-term incentive compensation plan which expired pursuant to its terms on December 31, 2020, but it will continue to govern outstanding equity awards granted thereunder. The compensation cost charged against income for these plans was $39.8$29.7 million,, $22.8 $41.5 million and $26.9$39.0 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting is to expense the costs ratably over the vesting periods.


Additionally, HEP maintains a share-based compensation plan for Holly Logistic Services, L.L.C.'s non-employee directors and certain executives and employees. Compensation cost attributable to HEP’s share-based compensation plan was $2.5$2.2 million,, $2.7 $2.5 million and $3.5$3.2 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.


Restricted Stock and Restricted Stock Units
Under our Long-Term Incentive Compensation Plan,long-term incentive plan, we grant certain officers and other key employees restricted stock unit awards, with awardswhich are payable in stock or cash and generally vesting over a period of two to three years. We previously granted restricted stock to certain officers and key employees with awards vestingvest over a period of three years. Certain restrictedRestricted stock unit award recipients have the right to receive dividends, however, restricted stock units do not have any other rights of absolute ownership. Restricted stock award recipients are generally entitled to all the rights of absolute ownership of the restricted shares from the date of grant including the right to vote the shares and to receive dividends. Upon vesting, restrictions on the restricted shares and restricted sharestock units lapse at which time they convert to common shares.shares or cash. In addition, we grant non-employee directors restricted stock unit awards, which typically vest over a period of one year and are payable in stock. The fair value of each restricted stock and restricted stock unit award is measured based on the grant date market price of our common shares and is amortized over the respective vesting period. We account for forfeitures on an estimated basis.


90

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

A summary of restricted stock and restricted stock unit activity and changes during the year ended December 31, 20172020 is presented below:
Restricted Stock UnitsGrantsWeighted Average Grant Date Fair ValueAggregate Intrinsic Value ($000)
Outstanding at January 1, 20201,101,781 $53.30 
Granted1,574,929 $22.20 
Vested(549,144)$51.40 
Forfeited(89,971)$53.66 
Converted from performance share units19,450 $38.13 
Outstanding at December 31, 20202,057,045 $29.76 $53,175 
Restricted Stock and Restricted Stock Units Grants Weighted Average Grant Date Fair Value Aggregate Intrinsic Value ($000)
       
Outstanding at January 1, 2017 (non-vested) 1,188,774
 $28.87
  
Granted (1)
 1,426,106
 35.02
  
Vesting (transfer/conversion to common stock) (817,601) 30.41
  
Forfeited (71,091) 30.20
  
Outstanding at December 31, 2017 (non-vested) 1,726,188
 $33.51
 $88,415


(1) Includes restricted stock units issued to employees in the PCLI acquisition.

In connection with our February 1, 2017 PCLI acquisition, we issued 472,276 restricted stock units to PCLI employees as replacement units for unvested awards issued under the legacy PCLI plan. The fair value of these awards totaled $13.3 million and is based on a February 1, 2017 grant date value of $28.12 per unit. Of this total, $6.6 million is recognized as an increase to our PCLI purchase price as it represents the value of the awards attributable to pre-acquisition services, and the remaining $6.7 million is to be recognized as compensation expense over the two-year vesting period.

For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, restricted stock and restricted stock units vested having a grant date fair value of $24.9$28.2 million,, $18.4 $30.9 million and $14.2$30.0 million, respectively. For the years ended December 31, 20162019 and 2015,2018, we granted restricted stock and restricted stock units having a weighted average grant date fair value of $21.66$52.62 and $49.92,$64.96, respectively. As of December 31, 2017,2020, there was $33.9$40.4 million of total unrecognized compensation cost related to non-vested restricted stock and restricted stock unit grants. That cost is expected to be recognized over a weighted-average period of 1.61.7 years. For the years ended December 31, 2020, 2019 and 2018, we paid $1.3 million, $1.7 million and $0.1 million, respectively, in cash equal to the value of the stock award on the vest date to certain employees to settle 55,222, 32,648 and 2,481, respectively, restricted stock units.


Performance Share Units
Under our Long-Term Incentive Compensation Plan,long-term incentive plan, we grant certain officers and other key employees performance share units, which are payable in stock or cash upon meeting certain criteria over the service period, and generally vest over a period of three years. Under the terms of our performance share unit grants, awards are subject to “financial performance” and “market performance” criteria. Financial performance is based on our financial performance compared to a peer group of independent refining companies, while market performance is based on the relative standing of total shareholder return achieved by HollyFrontier compared to peer group companies. The number of shares ultimately issued or cash paid under these awards can range from zero0 to 200% of target award amounts. AsHolders ofDecember 31, 2017, estimated share payouts for outstanding non-vested performance share unit awards averaged approximately 110%units have the right to receive dividend equivalents and other distributions with respect to such performance share units based on the target level of target amounts.payout.



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


A summary of performance share unit activity and changes during the year ended December 31, 20172020 is presented below:
Performance Share UnitsGrants
Outstanding at January 1, 2017 (non-vested)2020703,939375,588 
Granted239,964434,378 
Vesting and transfer of ownership to recipientsVested(151,599(124,303))
Forfeited(99,643(31,009))
Converted to restricted stock units(19,450)
Outstanding at December 31, 2017 (non-vested)2020692,661635,204 


For the year ended December 31, 2017,2020, we issued 138,374296,801 shares of common stock, representing a 91%150% payout on vested performance share units having a grant date fair value of $6.6 million.$6.2 million. For the years ended December 31, 20162019 and 2015,2018, we issued common stock upon the vesting of the performance share units having a grant date fair value of $7.4$7.3 million and $10.4$8.8 million, respectively. As of December 31, 2017,2020, there was $15.6$14.5 million of total unrecognized compensation cost related to non-vested performance share units having a grant date fair value of $33.94$35.45 per unit. That cost is expected to be recognized over a weighted-average period of 2.12.5 years.



NOTE 7:Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio at December 31, 2017 consisted of cash and cash equivalents.

We periodically invest in marketable debt securities with the maximum maturity or put date of any individual issue generally not greater than one year from the date of purchase, which are usually held until maturity. All of these instruments are classified as available-for-sale and are reported at fair value. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income. Upon sale or maturity, realized gains on our marketable debt securities are recognized as interest income. These gains are computed based on the specific identification of the underlying cost of the securities, net of unrealized gains and losses previously reported in other comprehensive income. Unrealized gains and losses on our available-for-sale securities are due to changes in market prices and are considered temporary.

The following is a summary of our marketable securities at December 31, 2016:
91
  Amortized Cost Gross Unrealized Gain Gross Unrealized Loss 
Fair Value
(Net Carrying Amount)
  (In thousands)
December 31, 2016        
Commercial paper $7,687
 $1
 $(1) $7,687
Corporate debt securities 4,001
 —
 —
 4,001
State and political subdivisions debt securities 412,462
 1
 (3) 412,460
Total marketable securities $424,150
 $2
 $(4) $424,148

Interest income recognized on our marketable securities was $0.3 million, $0.8 million and $1.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.




HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



NOTE 8:Inventories

NOTE 9:Inventories

Inventory consists of the following components:
December 31,
20202019
(In thousands)
Crude oil$451,967 $489,169 
Other raw materials and unfinished products(1)
260,495 394,045 
Finished products(2)
572,258 639,938 
Lower of cost or market reserve(318,862)(240,363)
Process chemicals(3)
35,006 36,786 
Repairs and maintenance supplies and other (4)
172,612 154,627 
Total inventory$1,173,476 $1,474,202 
  December 31,
  2017 2016
  (In thousands)
Crude oil $581,417
 $549,886
Other raw materials and unfinished products(1)
 396,618
 287,561
Finished products(2)
 655,336
 465,432
Lower of cost or market reserve (223,833) (332,518)
Process chemicals(3)
 24,792
 2,767
Repairs and maintenance supplies and other (4)
 195,762
 162,548
Total inventory $1,630,092
 $1,135,676


(1)(1)Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.
(2)Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPG’s and residual fuels.
(3)Process chemicals include additives and other chemicals.
(4)Includes RINs

We acquired $214.9 million of other raw materials and unfinished products include feedstocks and finishedblendstocks, other than crude.
(2)Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPG’s and repairresidual fuels.
(3)Process chemicals include additives and maintenance supplies in connection with our February 1, 2017 acquisition of PCLI. We value theseother chemicals.
(4)Includes RINs

Our inventories at the lower of FIFO cost or net realizable value.

Inventories whichthat are valued at the lower of LIFO cost or market reflect a valuation reserve of $223.8$318.9 million and $332.5$240.4 million at December 31, 20172020 and 2016,2019, respectively. The December 31, 20162019 market reserve of $332.5$240.4 million was reversed due to the sale of inventory quantities that gave rise to the 20162019 reserve. A new market reserve of $223.8$318.9 million was established as of December 31, 20172020 based on market conditions and prices at that time. The effect of the change in the lower of cost or market reserve was a decreasean increase to cost of goodsproducts sold of $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016, respectively, and an increase of $227.0totaling $78.5 million for the year ended December 31, 2015.2020, a decrease of $119.8 million for the year ended December 31, 2019 and an increase of $136.3 million for the year ended December 31, 2018.


At December 31, 2017, 20162020, 2019 and 2015,2018, the LIFO value of inventory, net of the lower of cost or market reserve, was equal to current costs. For the year ended December 31, 2020, we recognized a charge of $36.9 million to cost of products sold as we liquidated certain quantities of LIFO inventory at our Cheyenne Refinery that were carried at historical acquisition costs above market prices at the time of liquidation


In May 2017,During the three months ended September 30, 2019, the EPA granted the Cheyenne Refinery and the Woods Cross Refinery each a one-year small refinery exemption from the Renewable Fuel Standard (“RFS”) program requirements for the 20162018 calendar year.year end. As a result, the Cheyenne Refinery’s and the Woods Cross Refinery’s gasoline and diesel production are not subject to the percentage of production that must satisfy a Renewable Volume Obligation (“RVO”) for 2016. In September 2017, the EPA reinstated the RINs previously submitted to meet our Cheyenne Refinery’s 2016 RVO. The cost of the RINs used earlier to satisfy the Cheyenne Refinery’s 2016 RVO of $30.5 million was charged to cost of products sold in 2016.2018. In the secondthird quarter of 2017,2019, we increased our inventory of RINs and reduced our cost of products sold by this amount,$36.6 million representing the net cost of the RINs that were reinstated as a resultcharge to cost of products sold in 2018, less the RFS exemption received byloss incurred for selling 2018 vintage RINs in excess of those which we can use subject to the Cheyenne Refinery.20% carryover limit.


Additionally, in December 2017,During the three months ended June 30, 2018, the EPA granted the Woods Cross Refinery a one-year small refinery exemption from the RFS program requirements for the 20162017 calendar year.year end. As a result, the Woods Cross Refinery’s gasoline and diesel production are not subject to the RVO for 2017. In the fourthsecond quarter of 2017,2018, we increased our inventory of RINs and reduced our cost of products sold in the amount of $27.3by $25.3 million, representing the net cost of the Woods Cross Refinery’s RINs charge to cost of products sold in 2017, less the loss incurred for selling 2017 vintage RINs in excess of those which we can use subject to the 20% carryover limit.

During the three months ended March 31, 2018, the EPA granted the Cheyenne Refinery a one-year small refinery exemption from the RFS program requirements for the 2015 and 2017 calendar years end. As a result, the Cheyenne Refinery’s gasoline and diesel production are not subject to the RVO for those years. At the date we received the 2017 Cheyenne Refinery exemption, we had not yet retired RINs to be reinstated as a resultsatisfy the 2017 RVO, which we intended to satisfy, in part, with 2016 vintage RINs subject to the 20% carryover limit. In the first quarter of 2018, we increased our inventory of RINs and reduced our cost of products sold by $37.9 million, representing the net cost of the RFS exemption received byCheyenne Refinery’s RINs charged to cost of products sold in 2017, less the Woods Cross Refinery. Theseloss incurred from selling 2016 vintage RINs were reinstatedprior to their expiration in January 2018.




92

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



In the first quarter of 2018, the EPA provided us 2018 vintage RINs to replace the RINs previously retired to meet the Cheyenne Refinery’s 2015 RVO. In the first quarter of 2018, we increased our inventory of RINs and reduced our cost of products sold by $33.8 million representing the fair value of the 2018 replacement RINs obtained from the Cheyenne Refinery’s exemption of its 2015 RVO.


NOTE 9:Properties, Plants and Equipment

NOTE 10:Properties, Plants and Equipment

The components of properties, plants and equipment are as follows:
December 31,
20202019
(In thousands)
Land, buildings and improvements$517,829 $447,547 
Refining facilities4,202,524 4,258,764 
Pipelines and terminals1,786,279 1,775,657 
Transportation vehicles26,715 27,214 
Other fixed assets400,159 540,953 
Construction in progress366,011 187,162 
7,299,517 7,237,297 
Accumulated depreciation(2,726,378)(2,414,585)
$4,573,139 $4,822,712 
  December 31,
  2017 2016
  (In thousands)
Land, buildings and improvements $442,214
 $326,097
Refining facilities 3,904,161
 3,382,369
Pipelines and terminals 1,484,502
 1,392,898
Transportation vehicles 20,394
 18,841
Other fixed assets 467,469
 153,463
Construction in progress 205,049
 273,188
  6,523,789
 5,546,856
Accumulated depreciation (1,810,515) (1,538,408)
  $4,713,274
 $4,008,448


During the year ended December 31, 2016, we recorded impairment charges of $309.3 million that are attributable to properties, plant and equipment of our Cheyenne reporting unit. See Note 10 for additional information.

We capitalized interest attributable to construction projects of $5.0$4.1 million,, $8.0 $2.5 million and $5.5$4.8 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.


Depreciation expense was $286.5$333.0 million,, $247.9 $334.2 million and $233.3$309.0 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.




NOTE 10:Goodwill and Long-lived Asset Impairment

NOTE 11:Goodwill, Long-lived Assets and Intangibles

Goodwill and long-lived assets
As of December 31, 2017,2020, our goodwill balance was $2.2$2.3 billion. During 2017, we recognized $194.8 million in goodwill as a result of our PCLI acquisition. Also during 2017, HEP recognized $21.6 million in goodwill as a result of the acquisition of HEP's remaining interests in SLC Pipeline and Frontier Pipeline. See Note 20 for additional information on our segments. The carrying amount of our goodwill may fluctuate from period to period due to the effects of foreign currency translation adjustments on goodwill assigned to our Lubricants and Specialty Products segment.


93

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

The following is a summary of our goodwill by segment:
RefiningLubricants and Specialty ProductsHEPTotal
(In thousands)
Balance at December 31, 2019
Goodwill$2,042,790 $480,274 $312,873 $2,835,937 
Accumulated impairment losses(309,318)(152,712)0 (462,030)
1,733,472 327,562 312,873 2,373,907 
Foreign currency translation adjustment0 1,895 0 1,895 
Current year impairment losses0 (81,867)0 (81,867)
Balance at December 31, 2020
Goodwill2,042,790 482,169 312,873 2,837,832 
Accumulated impairment losses(309,318)(234,579)0 (543,897)
$1,733,472 $247,590 $312,873 $2,293,935 
  Refining Lubricants and Specialty Products HEP Total
  (In thousands)
Balance at December 31, 2016        
Goodwill $2,042,790
 $—
 $288,991
 $2,331,781
Accumulated impairment losses (309,318) —
 —
 (309,318)
  1,733,472
 —
 288,991
 2,022,463
         
Additional goodwill acquired —
 194,760
 21,619
 216,379
Foreign currency translation adjustment —
 5,902
 —
 5,902
         
Balance at December 31, 2017        
Goodwill 2,042,790
 200,662
 310,610
 2,554,062
Accumulated impairment losses (309,318) —
 —
 (309,318)
  $1,733,472
 $200,662
 $310,610
 $2,244,744


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



We performed our annual goodwillGoodwill and long-lived asset impairment testing as of July 1, 2017 and determined the fair value of our El Dorado reporting unit exceeded its carrying value by approximately 10%. A reasonable expectation exists that future deterioration in gross margins could result in an impairment of goodwill and the long-lived assets of the El Dorado reporting unit as some point in the future and such impairment charges could be material. Additionally, qualitative testing indicated no impairment of goodwill attributable to our other reporting units.

During the second quarter of 2017,2020, we incurreddetermined that indicators of potential goodwill and long-lived asset impairments were present and performed recoverability testing for long-lived assets and an interim test for goodwill impairment charges totaling $23.2 million, including $19.2 millionas of construction-in-progress consisting primarily of engineering work for a planned expansionMay 31, 2020. Impairment indicators included the recent economic slowdown caused by the COVID-19 pandemic, reductions in the prices of our Woods Cross refinery to add lubricants production capabilities. Duringfinished goods and raw materials and the related decrease in our gross margins, as well as the recent decline in our market capitalization. Additionally, our second quarter announcement of 2017, we concludedthe planned conversion of our Cheyenne Refinery to no longer pursue this expansion for various reasons includingrenewable diesel production was also considered a triggering event requiring assessment of potential impairments to the carrying value of our recent acquisition of PCLI. The remaining $4.0 million in charges relate to property, plant and equipment that we expensed in the form of accelerated depreciation in the income statement. Additionally, asCheyenne Refinery asset group. As a result of our impairmentlong-lived asset recoverability testing, in the second quarter of 2016, we determined that the carrying value of the long-lived assets of theour Cheyenne Refinery had been impaired and PCLI asset groups were not recoverable, and thus recorded long-lived asset impairment charges of $344.8$232.2 million that principally related to properties, plant and equipment.

During$204.7 million, respectively, in the second quarter of 2016, we performed2020. Our interim goodwill impairment testing indicated that there was no impairment of goodwill at our Refining and relatedLubricants and Specialty Products reporting units as of May 31, 2020. The estimated fair values of the Cheyenne Refinery and PCLI asset groups were determined using a combination of the income and cost approaches. The income approach was based on management’s best estimates of the expected future cash flows over the remaining useful life of the asset group. The cost approach utilized assumptions for the current replacement costs of similar assets adjusted for estimated depreciation and economic obsolescence. These fair value measurements involve significant unobservable inputs (Level 3 inputs). See Note 6 for further discussion of Level 3 inputs.

As of July 1, 2020, we performed our annual goodwill impairment testing quantitatively and determined there was no impairment of goodwill attributable to our reporting units at that time.

During the fourth quarter of 2020, we incurred long-lived asset impairment testingcharges of $26.5 million for construction-in-progress, consisting primarily of engineering work for potential upgrades to certain processing units at our Tulsa and El Dorado Refineries. During the quarter, we concluded not to pursue these projects in light of recent economic and Cheyenne Refinery reporting units after identifying a combination of events and circumstances that are indicatorsmarket conditions.
of potential goodwill and long-lived asset impairment. The indicators included lower than typical gross margins during the summer driving season, a decrease
Additionally, in the fourth quarter of 2020, our annual budgeting process identified downward forecast revisions specific to the Sonneborn reporting unit within our Lubricants and Specialty Products segment; largely from declines in gross margin outlookas compared to historic levels and decreasean increase in our market capitalization due to a decline in our common share price. Our testing first assessedforecasted capital expenditures. As such, we concluded it was more likely than not that the carrying valuesvalue of our refining long-lived asset groups for recoverability. This entailed a comparison of ourthe Sonneborn reporting unit fair values relative to their respective carrying values. If carrying value exceedsexceeded its fair value, for a reporting unit,and we measureperformed an interim quantitative test for goodwill impairment as of December 1, 2020. As a result of our impairment testing, we recognized a goodwill impairment charge of $81.9 million during the excess offourth quarter for the carrying amount of reporting unit goodwill over the implied fair value of that goodwill based on estimates of the fair value of all assets and liabilities in theSonneborn reporting unit. No other reporting units required an interim impairment test during the fourth quarter.

94

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

The estimated fair values of our goodwill reporting units and long-lived asset groupstested quantitatively in the current year were derived using a combination of both income and market approaches. The income approach reflects expected future cash flows based on estimates of future crack spreads,estimated forecasted production levels, selling prices, gross margins, operating costs and capital expenditures. Our 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-kindlike kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs). As a resultSee Note 6 for further discussion of ourLevel 3 inputs.

There was no impairment testingof long-lived assets during the second quarter of 2016,years ended December 31, 2019 and 2018.

During the year ended December 31, 2019, we determined that the carrying value of the Cheyenne Refinery’s goodwill was fully impaired andrecorded a goodwill impairment charge of $309.3$152.7 million was recorded, representing allto fully impair the goodwill of the goodwill allocated toPCLI reporting unit included in our Cheyenne Refinery. Our interim testing in 2016 did not identify anyLubricants and Specialty Products segment. There was 0 impairment related to our El Dorado reporting unit.

There were no impairments of goodwill or long-lived assets during the year ended December 31, 2015.2018.



A reasonable expectation exists that further deterioration in our operating results or overall economic conditions could result in an impairment of goodwill and / or additional long-lived assets impairments at some point in the future. Future impairment charges could be material to our results of operations and financial condition.
NOTE 11:Environmental


We expensed $13.1Intangibles
The carrying amounts of our intangible assets presented in “Intangibles and other” in our consolidated balance sheet are as follows:
December 31
Useful Life20202019
 (In thousands)
Customer relationships 10 - 20 years$239,773 $245,479 
Transportation agreements30 years59,933 59,933 
Trademarks, patents and other10 - 20 years157,120 154,863 
456,826 460,275 
Accumulated amortization(122,024)(86,768)
Total intangibles, net$334,802 $373,507 

Amortization expense was $34.1 million,, $6.6 $33.8 million and $14.7$16.6 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively and expected to approximate $34.1 million for each of the next five years.


NOTE 12:Environmental

We expensed $7.1 million, $11.2 million and $14.8 million for the years ended December 31, 2020, 2019 and 2018, respectively, for environmental remediation obligations. The accrued environmental liability reflected in our consolidated balance sheets was $103.7$115.0 million and $96.4$117.7 million at December 31, 20172020 and 2016,2019, respectively, of which $89.6$94.0 million and $82.9$95.6 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 (up to 30 years for certain projects). The amount of our accrued liability includes $2.9 million of environmental obligations assumed in connection with our February 1, 2017 PCLI acquisition. Estimated liabilities could increase in the future when the results of ongoing investigations become known, are considered probable and can be reasonably estimated.



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ContinuedNOTE 13:Debt



NOTE 12:Debt


HollyFrontier Credit Agreement
We have a $1.35 billion senior unsecured revolving credit facility maturing in February 2022 (the “HollyFrontier Credit Agreement”). The HollyFrontier Credit Agreement may be used for revolving credit loans and letters of credit from time to time and is available to fund general corporate purposes. During the year endedAt December 31, 2017, we received advances totaling $26.0 million and repaid $26.0 million under the HollyFrontier Credit Agreement. At December 31, 2017,2020, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $2.8$5.7 million under the HollyFrontier Credit Agreement.


95

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Indebtedness under the HollyFrontier Credit Agreement bears interest, at our option at either a) an alternate base rate (as defined in the credit agreement) plus an applicable margin of (ranging from 0.125% - 1.000%), b) LIBOR plus an applicable margin (ranging from 1.125% to 2.000%), or c) Canadian Dealer Offered Rate plus an applicable margin (ranging from 1.125% to 2.000%) for Canadian dollar denominated borrowings.


HEP Credit Agreement
HEP has a $1.4 billion senior secured revolving credit facility maturing in July 2022 (the “HEP Credit Agreement”) and is available to fund capital expenditures, investments, acquisitions, distribution payments, working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and has a $300 million accordion. During the year ended December 31, 2017,2020, HEP received advances totaling $969.0$258.5 million and repaid $510.0$310.5 million under the HEP Credit Agreement. At December 31, 2017,2020, HEP was in compliance with all of its covenants, had outstanding borrowings of $1,012.0$913.5 million and no outstanding letters of credit under the HEP Credit Agreement.


Indebtedness under the HEP Credit Agreement bears interest, at HEP's option, at either a reference rate announced by the administrative agent plus an applicable margin or at a rate equal to LIBOR plus an applicable margin. In each case, the applicable margin is based upon the ratio of HEP’s funded debt to earnings before interest, taxes, depreciation and amortization (as defined in the HEP Credit Agreement). The weighted average interest rates in effect on HEP’s Credit Agreement borrowings were 3.73% was 2.58%and 2.98% at 4.24% for December 31, 20172020 and 2016,2019, respectively.


HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets and are guaranteed by HEP's material wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP are not significant. HEP’s creditors have no recourse to our other assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.


HollyFrontier Senior Notes
In March 2016On September 28, 2020, we completed a public offering of $350.0 million in aggregate principal amount of 2.625% senior notes maturing October 2023 (the “2.625% Senior Notes”) and November 2016, we issued $250$400.0 million and $750 million, respectively,in aggregate principal amount of 4.500% senior notes maturing October 2030 (the “4.500% Senior Notes”). We intend to use the net proceeds for general corporate purposes, which may include capital expenditures.

As a result, as of December 31, 2020, our outstanding senior notes consist of $1.0 billion in aggregate principal amount of 5.875% senior notes maturing April 2026 (the “5.875% Senior Notes”), the 2.625% Senior Notes and the 4.500% Senior Notes (collectively, the “HollyFrontier Senior Notes”) maturing April 2026.. The HollyFrontier Senior Notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.


HollyFrontier Financing Arrangements
In June 2015,December 2018, certain of our wholly-owned subsidiaries entered into financing arrangements whereby such subsidiaries sold a portion of their precious metals catalyst to a financial institution and then leased back the precious metals catalyst in exchange for total cash received of $32.5 million. The volume of the precious metals catalyst and the lease rate are fixed over the term of each lease, and the lease payments are recorded as interest expense. The leases mature on February 1, 2022. Upon maturity, we must either satisfy the obligation at fair market value or refinance to extend the maturity. These financing arrangements are recorded at a Level 2 fair value totaling $43.9 million and $40.0 million at December 31, 2020 and 2019, respectively, and are included in “Accrued liabilities” in our consolidated balance sheets. See Note 6 for additional information on Level 2 inputs.

HEP Senior Notes
On February 4, 2020, HEP closed a private placement of $500.0 million in aggregate principal amount of 5.0% HEP senior unsecured notes maturing in February 2028 (the “HEP Senior Notes”). On February 5, 2020, HEP redeemed our $150.0its existing $500.0 million aggregate principal amount of 6.875%6.0% senior notes maturing November 2018August 2024 at a redemption cost of $155.2 million at which time we$522.5 million. HEP recognized a $1.4$25.9 million early extinguishment loss consisting of a $5.2$22.5 million debt redemption premium netand unamortized discount and financing costs of an unamortized premium of $3.8$3.4 million.

HollyFrontier Financing Obligation
In March 2016, we extinguished a financing obligation at a cost of $39.5 HEP funded the $522.5 million and recognized an $8.7 million loss on the early termination. The financing obligation related to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains in October 2009 for $40.0 million.

HollyFrontier Term Loan
In April 2016, we entered into a $350 million senior unsecured term loan (the “HollyFrontier Term Loan”) maturing in April 2019. The HollyFrontier Term Loan was fully repaidredemption with proceeds received uponfrom the November 2016 issuance of the HollyFrontier Senior Notes.


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


HEP Senior Notes
In July 2016 and September 2017, HEP issued $400 million and $100 million, respectively, in aggregate principal amount of 6.0% HEPits 5.0% senior notes in a private placement. HEP used the net proceeds to repay indebtednessand borrowing under the HEP Credit Agreement.


HEP's 6.0% senior notes ($500 million aggregate principal amount maturing August 2024) (the “HEP
96

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

The HEP Senior Notes”)Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. HEP was in compliance with the restrictive covenants for the HEP Senior Notes as of December 31, 2020. At any time when the HEP Senior Notes are rated investment grade by botheither Moody’s andor Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes.

In January 2017, HEP redeemed its $300 million aggregate principal amount of 6.5% senior notes maturing March 2020 at a redemption cost of $309.8 million, at which time HEP 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. HEP funded the redemption with borrowings under the HEP Credit Agreement.


Indebtedness under the HEP Senior Notes is guaranteed by HEP’s wholly-owned subsidiaries. HEP’s creditors have no recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.


The carrying amounts of long-term debt are as follows:
December 31,
20202019
 (In thousands)
HollyFrontier
2.625% Senior Notes$350,000 $0 
5.875% Senior Notes1,000,000 1,000,000 
4.500% Senior Notes400,000 0 
1,750,000 1,000,000 
Unamortized discount and debt issuance costs(12,885)(6,391)
Total HollyFrontier long-term debt1,737,115 993,609 
HEP
HEP Credit Agreement913,500 965,500 
5.00% Senior Notes500,000 0 
6.00% Senior Notes0 500,000 
500,000 500,000 
Unamortized discount and debt issuance costs(7,897)(3,469)
Total HEP long-term debt1,405,603 1,462,031 
Total long-term debt$3,142,718 $2,455,640 
  December 31,
  2017 2016
  (In thousands)
HollyFrontier 5.875% Senior Notes    
Principal $1,000,000
 $1,000,000
Unamortized discount and debt issuance costs (8,315) (8,775)
  991,685
 991,225
     
HEP Credit Agreement 1,012,000
 553,000
     
HEP 6% Senior Notes    
Principal 500,000
 400,000
Unamortized discount and debt issuance costs (4,692) (6,607)
  495,308
 393,393
     
HEP 6.5% Senior Notes    
Principal —
 300,000
Unamortized discount and debt issuance costs —
 (2,481)
  —
 297,519
     
Total HEP long-term debt 1,507,308
 1,243,912
     
Total long-term debt $2,498,993
 $2,235,137


The fair values of the senior notes are as follows:
December 31,
20202019
(In thousands)
HollyFrontier Senior Notes$1,903,867 $1,127,610 
HEP Senior Notes$506,540 $522,045 
  December 31,
  2017 2016
  (In thousands)
     
HollyFrontier senior notes $1,113,470
 $1,022,500
     
HEP senior notes $525,120
 $723,750


These fair values are based on estimates provided by a third party using market quotes for similar type instruments, a Level 2 input. See Note 46 for additional information on Level 2 inputs.



97

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



Principal maturities of long-term debt as of December 31, 2020 are as follows:

Years Ending December 31,(In thousands)
2021$0 
2022913,500 
2023350,000 
20240 
20250 
Thereafter1,900,000 
Total$3,163,500 


Years Ending December 31,(In thousands)
2018$—
2019—
2020—
2021—
20221,012,000
Thereafter1,500,000
Total$2,512,000


NOTE 13:Derivative Instruments and Hedging Activities

NOTE 14:Derivative Instruments and Hedging Activities

Commodity Price Risk Management
Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative contracts in the form of commodity price swaps, forward purchase and sales and futures contracts to mitigate price exposure with respect to:
to our inventory positions;
positions, natural gas purchases;
costs of crude oil and related grade differentials;
purchases, sales prices of refined products;products and crude oil costs.

Foreign Currency Risk Management
We are exposed to market risk related to the volatility in foreign currency exchange rates. We periodically enter into derivative contracts in the form of foreign exchange forward and foreign exchange swap contracts to mitigate the exposure associated with fluctuations on intercompany notes with our refining margins.foreign subsidiaries that are not denominated in the U.S. dollar.


Accounting Hedges
We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas. We also periodically have swap contracts to lock in basis spread differentials on forecasted purchases of crude oil and forward sales contracts that lock in the prices of future sales of crude oil and refined product and swap contracts serving as cash flow hedges against price risk on forecasted purchases of WTI crude oil and forecasted sales of refined product. These contracts have been designated as accounting hedges and are measured at fair value with offsetting adjustments (gains/losses) recorded directly to other comprehensive income. These fair value adjustments are later reclassified to earnings as the hedging instruments mature. On a quarterly basis, hedge ineffectiveness is measured by comparing the change in fair value of the swap contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is also recognized in earnings.


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



The following table presents the pre-tax effect on other comprehensive income (“OCI”) and earnings due to fair value adjustments and maturities of commodity price swaps and forward saleshedging instruments under hedge accounting:
Net Unrealized Gain (Loss) Recognized in OCIGain (Loss) Reclassified into Earnings
Derivatives Designated as Cash Flow Hedging InstrumentsYears Ended December 31,Income Statement LocationYears Ended December 31,
202020192018202020192018
(In thousands)
Commodity contracts$(4,871)$(5,349)$11,221 Sales and other revenues$(5,168)$(1,799)$(5,093)
Cost of products sold4,281 22,876 0 
Operating expenses(1,717)(1,364)(962)
Total$(4,871)$(5,349)$11,221 $(2,604)$19,713 $(6,055)
98

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

  Unrealized Gain (Loss) Recognized in OCI Gain (Loss) Recognized in Earnings Due to Settlements Gain (Loss) Attributable to Hedge Ineffectiveness Recognized in Earnings
   Location Amount Location Amount
    (In thousands)
Year Ended December 31, 2017          
Commodity price swaps          
Change in fair value $2,831
 Sales and other revenues $7,836
    
Loss reclassified to earnings due to settlements 10,627
 Cost of products sold (299)    
Amortization of discontinued hedges reclassified to earnings 1,080
 Operating expenses (19,244) Operating expenses $(54)
Total $14,538
   $(11,707)   $(54)
           
Year Ended December 31, 2016          
Commodity price swaps          
Change in fair value $(17,018)        
Loss reclassified to earnings due to settlements 41,077
 Sales and other revenues $(20,293)    
Amortization of discontinued hedges reclassified to earnings 1,080
 Operating expenses (21,864) Operating expenses $—
Total $25,139
   $(42,157)   $—
           
Year Ended December 31, 2015          
Commodity price swaps          
Change in fair value $(3,983) Sales and other revenues $245,819
 Sales and other revenues $(274)
Gain reclassified to earnings due to settlements (49,592) Cost of products sold (179,700) Cost of products sold 4,376
Amortization of discontinued hedges reclassified to earnings 1,080
 Operating expenses (17,607) Operating expenses 547
Total $(52,495)   $48,512
   $4,649

As of December 31, 2017, we have the following notional contract volumes related to outstanding derivative instruments serving as cash flow hedges against price risk on forecasted transactions:
    Notional Contract Volumes by Year of Maturity  
Derivative Instrument Total Outstanding Notional 2018 2019 2020 2021 Unit of Measure
             
Natural gas price swaps - long 7,200,000
 1,800,000
 1,800,000
 1,800,000
 1,800,000
 MMBTU
Forward gasoline and diesel contracts - short 250,000
 250,000
 —
 —
 —
 Barrels
Forward crude oil contracts - short 276,751
 276,751
 —
 —
 —
 Barrels


Economic Hedges
We also have commodity forward contracts andincluding NYMEX futures contracts to lock in prices on forecasted purchases and sales of inventory. In addition, weinventory and forward purchase and sell contracts, as well as periodically have contracts to lock in basis spread differentials on forecasted purchases of crude oil and swap contracts to lock in the crack spread of WTI and gasoline, that serve as economic hedges (derivatives used for risk management, but not designated as accounting hedges). We also have forward currency contracts to lockfix the rate of foreign currency. In addition, our catalyst financing arrangements discussed in basis spread differentialsNote 13 could require repayment under certain conditions based on forecasted purchasesthe future pricing of crude oil and natural gas. Furthermore, we had Canadian currency swap contracts that effectively fixed the conversion rate on $1.125 billion Canadian dollars (the PCLI purchase price),platinum, which were settled on February 1, 2017, in connection with the closing of the PCLI acquisition.is an embedded derivative. These contracts are measured at fair value with offsetting adjustments (gains/(gains / losses) recorded directly to income.


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges:
Gain (Loss) Recognized in Earnings
Derivatives Not Designated as Hedging InstrumentsYears Ended December 31,
Income Statement Location202020192018
(In thousands)
Commodity contractsCost of products sold$18,646 $(8,475)$16,655 
Interest expense(4,250)(6,427)(198)
Foreign currency contractsGain on foreign currency transactions(7,300)(17,430)41,834 
Total$7,096 $(32,332)$58,291 
  Years Ended December 31,
Location of Gain (Loss) Recognized in Earnings 2017 2016 2015
  (In thousands)
Cost of products sold $(12,327) $(6,889) $48,082
Operating expenses (6,697) 7,276
 (12,003)
Gain (loss) on foreign currency swap 24,545
 (6,520) —
Total $5,521
 $(6,133) $36,079



As of December 31, 2017,2020, we have the following notional contract volumes related to our outstanding derivative contracts serving as economic hedgesinstruments (all maturing in 2018)2021):

Derivative InstrumentTotal Outstanding NotionalUnit of Measure
Derivatives designated as hedging instruments:
Natural gas price swaps - long1,800,000 MMBTU
Derivatives not designated as hedging instruments:
NYMEX futures (WTI) - short1,175,000160,000 
Barrels
Forward gasoline and diesel contracts - long85,000195,000 
Barrels
Foreign currency forward contracts418,192,532 U. S. dollar
Forward commodity contracts (platinum)40,867 Troy ounces

Interest Rate Risk Management
HEP used interest rate swaps to manage its exposure to interest rate risk. These swap contracts, which matured in July 2017, had been designated as cash flow hedges.

The following table presents the pre-tax effect on other comprehensive income and earnings due to fair value adjustments and maturities of HEP's interest rate swaps under hedge accounting:
99
  Unrealized Gain (Loss) Recognized in OCI Income (Loss) Recognized in Earnings Due to Settlements
   Location Amount
  (In thousands)
Year Ended December 31, 2017      
Interest rate swaps      
Change in fair value $88
    
Gain reclassified to earnings due to settlements (179) Interest expense $179
Total $(91)   $179
       
Year Ended December 31, 2016      
Interest rate swaps      
Change in fair value $(607)    
Loss reclassified to earnings due to settlements 508
 Interest expense $(508)
Total $(99)   $(508)
       
Year Ended December 31, 2015      
Interest rate swaps      
Change in fair value $(1,864)    
Loss reclassified to earnings due to settlements 2,100
 Interest expense $(2,100)
Total $236
   $(2,100)



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



The following table presents the fair value and balance sheet locations of our outstanding derivative instruments. These amounts are presented on a gross basis with offsetting balances that reconcile to a net asset or liability position in our consolidated balance sheets. We present on a net basis to reflect the net settlement of these positions in accordance with provisions of our master netting arrangements.
Derivatives in Net Asset PositionDerivatives in Net Liability Position
Gross AssetsGross Liabilities Offset in Balance SheetNet Assets Recognized in Balance SheetGross LiabilitiesGross Assets Offset in Balance SheetNet Liabilities Recognized in Balance Sheet
 (In thousands)
December 31, 2020
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts$0 $0 $0 $359 $0 $359 
$0 $0 $0 $359 $0 $359 
Derivatives not designated as cash flow hedging instruments:
NYMEX futures contracts$0 $0 $0 $418 $0 $418 
Commodity forward contracts275 0 275 196 0 196 
Foreign currency forward contracts0 0 0 23,005 0 23,005 
$275 $0 $275 $23,619 $0 $23,619 
Total net balance$275 $23,978 
Balance sheet classification:Prepayment and other$275 Accrued liabilities$23,978 
  Derivatives in Net Asset Position Derivatives in Net Liability Position
  Gross Assets Gross Liabilities Offset in Balance Sheet Net Assets Recognized in Balance Sheet Gross Liabilities Gross Assets Offset in Balance Sheet Net Liabilities Recognized in Balance Sheet
    (In thousands)  
December 31, 2017            
Derivatives designated as cash flow hedging instruments:  
Commodity price swap contracts $—
 $—
 $—
 $2,424
 $—
 $2,424
Commodity forward contracts 3,067
 —
 3,067
 418
 —
 418
  $3,067
 $—
 $3,067
 $2,842
 $—
 $2,842
             
Derivatives not designated as cash flow hedging instruments:  
NYMEX futures contracts $—
 $—
 $—
 $3,360
 $—
 $3,360
Commodity forward contracts 773
 —
 773
 602
 —
 602
  $773
 $—
 $773
 $3,962
 $—
 $3,962
             
Total net balance     $3,840
     $6,804
             
Balance sheet classification: 
   Accrued liabilities $5,365
  
   Other long-term liabilities 1,439
  Prepayment and other $3,840
     $6,804


Derivatives in Net Asset PositionDerivatives in Net Liability Position
Gross AssetsGross Liabilities Offset in Balance SheetNet Assets Recognized in Balance SheetGross LiabilitiesGross Assets Offset in Balance SheetNet Liabilities Recognized in Balance Sheet
 (In thousands)
December 31, 2019
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts$7,526 $(1,784)$5,742 $1,230 $0 $1,230 
$7,526 $(1,784)$5,742 $1,230 $0 $1,230 
Derivatives not designated as cash flow hedging instruments:
NYMEX futures contracts$0 $0 $0 $2,578 $0 $2,578 
Commodity price swap contracts7,713 0 7,713 0 0 0 
Commodity forward contracts4,133 0 4,133 3,685 0 3,685 
Foreign currency forward contracts0 0 0 6,722 0 6,722 
$11,846 $0 $11,846 $12,985 $0 $12,985 
Total net balance$17,588 $14,215 
Balance sheet classification:Prepayments and other$17,588 Accrued liabilities$12,985 
Other long-term liabilities1,230 
$17,588 $14,215 



  Derivatives in Net Asset Position Derivatives in Net Liability Position
  Gross Assets Gross Liabilities Offset in Balance Sheet Net Assets Recognized in Balance Sheet Gross Liabilities Gross Assets Offset in Balance Sheet Net Liabilities Recognized in Balance Sheet
    (In thousands)  
December 31, 2016  
Derivatives designated as cash flow hedging instruments:  
Commodity price swap contracts $—
 $—
 $—
 $13,185
 $(431) $12,754
Commodity forward contracts —
 —
 —
 2,978
 —
 2,978
Interest rate swap contracts 91
 —
 91
 —
 —
 —
  $91
 $—
 $91
 $16,163
 $(431) $15,732
             
Derivatives not designated as cash flow hedging instruments:  
Commodity price swap contracts $4,244
 $(756) $3,488
 $12,903
 $(9,887) $3,016
NYMEX futures contracts —
 —
 —
 1,975
 —
 1,975
Commodity forward contracts 5,905
 —
 5,905
 5,338
 —
 5,338
Foreign currency forward contracts —
 —
 —
 6,519
 —
 6,519
  $10,149
 $(756) $9,393
 $26,735
 $(9,887) $16,848
             
Total net balance     $9,484
     $32,580
             
Balance sheet classification: Prepayment and other $9,484
 Accrued liabilities $32,580


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


At December 31, 2017,2020, we had a pre-tax net unrealized loss of $1.3$0.4 million classified in accumulated other comprehensive income that relates to all accounting hedges having contractual maturities through 2021. Assuming2021, which assuming commodity prices remain unchanged an unrealized gain of $0.1 million will be effectively transferred from accumulated other comprehensive income into the statement of income as the hedging instruments contractually mature over the next twelve-month period.



100

NOTE 14:Income Taxes

HOLLYFRONTIER CORPORATION
The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. The Act reduces the U.S. federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously deferred and creates new taxes on certain foreign sourced earnings. At December 31, 2017, we have not completed our accounting for the tax effects of enactment of the Act; however, in certain cases, as described below, we have made a reasonable estimate of the effects on our existing deferred tax balances, the one-time transition tax and related matters. For the items for which a reasonable estimate has been made, we recognized a provisional tax benefit amount of $307.1 million, which is included as a component of the income tax provision in 2017.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued
Provisional Amounts


Deferred Tax Assets and Liabilities: We remeasured certain deferred tax assets and liabilities based upon the rates at which they are expected to reverse in the future, which is generally 25%. However, we are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. The provisional amount recorded that related to remeasurement of our deferred tax balance was a tax benefit of $315.0 million. Included within our net deferred liability are deferred state income tax balances, which are recorded net of federal tax expense. While many states have not publicly commented on the changes in the Act, we have estimated the value of our state deferred tax balances based upon existing law and related guidance.

NOTE 15:Income Taxes
Foreign Tax Effects: The one-time transition tax is based on our foreign subsidiaries’ earnings and profits (“E&P”) arising primarily from our acquisition of PCLI in 2017. This E&P was previously deferred from U.S. income taxes at 35% plus the effect of U.S. state income tax, or together generally 38%. We previously provided deferred U.S. taxes for the repatriation of these deferred amounts. At December 31, 2017, we recorded a provisional amount for our one-time transition tax liability of $6.5 million for our foreign subsidiaries at 15.5% plus the effect of state income tax, or together generally 20%. We have not yet completed our calculation of the total foreign E&P for these foreign subsidiaries. This amount may change when we finalize the calculation of foreign E&P previously deferred from U.S. federal taxation. Additional income taxes have been provided for the remaining outside basis difference inherent in these entities at 21% plus the effect of U.S. state income tax, or together generally 25% as these amounts are not considered to be indefinitely reinvested in foreign operations for which we have provided deferred taxes of $1.4 million.

Our accounting for these provisional amounts related to foreign tax effects is incomplete pending the completion of our analysis of E&P, the related US foreign tax credits and outside basis differences.


The provision for income taxes is comprised of the following:
Years Ended December 31,
202020192018
(In thousands)
Current
Federal$(59,452)$187,134 $239,566 
State(5,391)29,547 40,788 
Foreign9,423 3,805 (10,080)
Deferred
Federal(64,836)77,916 46,434 
State(52,872)26,073 27,845 
Foreign(59,019)(25,323)2,690 
$(232,147)$299,152 $347,243 
  Years Ended December 31,
  2017 2016 2015
  (In thousands)
Current      
Federal $102,786
 $(71,878) $480,446
State 2,760
 (7,304) 71,750
Foreign 19,597
 —
 —
Deferred      
Federal (156,767) 100,208
 (127,714)
State 28,527
 (1,615) (18,422)
Foreign (9,282) —
 —
  $(12,379) $19,411
 $406,060

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued




The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense (benefit) as follows:
Years Ended December 31,
202020192018
(In thousands)
Tax computed at statutory rate$(156,880)$246,013 $320,138 
Effect of the Tax Cuts and Jobs Act0 0 (7,800)
State income taxes, net of federal tax benefit(41,566)47,259 56,936 
Noncontrolling interest in net income(21,799)(25,494)(20,215)
CARES Act benefits(19,837)— 0 
Foreign rate differential(14,294)0 0 
Effect of nondeductible goodwill impairment charge16,573 32,069 0 
Other5,656 (695)(1,816)
$(232,147)$299,152 $347,243 

101

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

  Years Ended December 31,
  2017 2016 2015
  (In thousands)
Tax computed at statutory rate $304,102
 $(60,037) $422,999
Effect of the Act (307,101) —
 —
State income taxes, net of federal tax benefit 21,343
 (14,056) 40,385
Domestic production activities deduction (9,937) 4,170
 (35,200)
Noncontrolling interest in net income (29,357) (26,903) (24,155)
Goodwill —
 119,722
 —
Other 8,571
 (3,485) 2,031
  $(12,379) $19,411
 $406,060

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities as of December 31, 20172020 and 20162019 are as follows:
December 31, 2020
AssetsLiabilitiesTotal
(In thousands)
Deferred income taxes
Properties, plants and equipment (due primarily to tax in excess of book depreciation)$— $(712,339)$(712,339)
Lease obligation94,447 — 94,447 
Accrued employee benefits21,819 — 21,819 
Accrued post-retirement benefits11,646 — 11,646 
Accrued environmental costs27,200 — 27,200 
Hedging instruments— (903)(903)
Inventory differences— (24,271)(24,271)
Deferred turnaround costs— (85,326)(85,326)
Net operating loss and tax credit carryforwards51,227 — 51,227 
Investment in HEP— (94,982)(94,982)
Valuation allowance— (8,577)(8,577)
Other6,356 — 6,356 
Total$212,695 $(926,398)$(713,703)
  December 31, 2017
  Assets Liabilities Total
  (In thousands)
Deferred income taxes      
Properties, plants and equipment (due primarily to tax in excess of book depreciation) $—
 $(560,957) $(560,957)
Accrued employee benefits 14,685
 —
 14,685
Accrued post-retirement benefits 10,358
 —
 10,358
Accrued environmental costs 28,657
 —
 28,657
Hedging instruments 16
 —
 16
Inventory differences —
 (35,501) (35,501)
Deferred turnaround costs —
 (58,645) (58,645)
Net operating loss and tax credit carryforwards 21,682
 —
 21,682
Investment in HEP —
 (62,321) (62,321)
Other —
 (5,759) (5,759)
Total $75,398
 $(723,183) $(647,785)


December 31, 2019
AssetsLiabilitiesTotal
(In thousands)
Deferred income taxes
Properties, plants and equipment (due primarily to tax in excess of book depreciation)$— $(809,966)$(809,966)
Lease obligation120,435 — 120,435 
Accrued employee benefits13,635 — 13,635 
Accrued post-retirement benefits11,027 — 11,027 
Accrued environmental costs28,708 — 28,708 
Hedging instruments— (2,439)(2,439)
Inventory differences— (43,500)(43,500)
Deferred turnaround costs— (135,920)(135,920)
Net operating loss and tax credit carryforwards22,912 — 22,912 
Investment in HEP— (95,037)(95,037)
Valuation allowance— (4,600)(4,600)
Other5,475 — 5,475 
Total$202,192 $(1,091,462)$(889,270)
  December 31, 2016
  Assets Liabilities Total
  (In thousands)
Deferred income taxes      
Properties, plants and equipment (due primarily to tax in excess of book depreciation) $—
 $(618,053) $(618,053)
Accrued employee benefits 21,355
 —
 21,355
Accrued post-retirement benefits 10,024
 —
 10,024
Accrued environmental costs 41,152
 —
 41,152
Hedging instruments 7,396
 —
 7,396
Inventory differences —
 (8,341) (8,341)
Deferred turnaround costs —
 (83,993) (83,993)
Net operating loss and tax credit carryforwards 23,203
 —
 23,203
Investment in HEP —
 (27,276) (27,276)
Other 14,119
 —
 14,119
Total $117,249
 $(737,663) $(620,414)


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



We have Kansas income tax credits of $12.8 million and Oklahoma income tax credits of $9.7$5.5 million that can be carried forward indefinitely,16 and Kansas income19 tax creditsyears, respectively. We also have net operating losses of $16.8$61.8 million in Luxembourg and $27.6 million in Canada. We have reflected a valuation allowance of $8.6 million in 2020 and $4.6 million in 2019 with respect to these net operating carry forwards that can be carried forward for 16 tax years.primarily relate to the losses in Luxembourg.

102

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Years Ended December 31,
202020192018
(In thousands)
Balance at January 1$56,621 $53,752 $53,752 
Additions for tax positions of prior years6 2,893 0 
Reductions for tax positions of prior years(1,500)(24)0 
Lapse of statute of limitations(228)0 0 
Balance at December 31$54,899 $56,621 $53,752 
  Years Ended December 31,
  2017 2016 2015
    (In thousands)  
Balance at January 1 $22,137
 $—
 $—
Additions based on tax positions related to the current year 31,615
 22,137
 —
Balance at December 31 $53,752
 $22,137
 $—


At December 31, 20172020, 2019 and 2016,2018, there were $53.8$54.9 million, $56.6 million, and $22.1$53.8 million, respectively, of unrecognized tax benefits that, if recognized, would affect our effective tax rate. We had no unrecognized benefits at December 31, 2015. Unrecognized tax benefits are adjusted in the period in which new information about a tax position becomes available or the final outcome differs from the amount recorded.


The 2016 and 2017 additions toApproximately $53.7 million of the unrecognized tax benefits relates to claims filed with the IRS on the federal income tax treatment of refundable biodiesel/ethanol blending tax credits for certain prior years. The issues related to the claims are complex and uncertain, and we cannot conclude that it is more likely than not that we will sustain the claims. Therefore, no tax benefit has been recognized for the filed claims. We believeDuring the next 12 months, it is reasonably possible that the total amounts ofan ultimate resolution regarding these claims could reduce unrecognized tax benefits will significantly increase within 12 months(due to possible court rulings in favor of the reporting date based on additional filings.IRS).


We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties.


We are subject to U.S. and Canadian federal income tax, Oklahoma, Kansas, New Mexico, Iowa, Arizona, Utah, Colorado and Nebraska income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all state and local income tax matters for tax years through 2012.through 2015. Other than the federal claim noted above, we have materially concluded all U.S. federal income tax matters for tax years through December 31, 2013.2016.



NOTE 15:Stockholders' Equity

NOTE 16:Stockholders' Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2017, 20162020, 2019 and 20152018 are presented below:
 Years Ended December 31,Years Ended December 31,
 2017 2016 2015202020192018
  
Common shares outstanding at January 1 177,345,266
 180,234,388
 196,086,090
Common shares outstanding at January 1161,846,525 172,121,491 177,407,622 
Issuance of restricted stock, excluding restricted stock with performance feature 55,626
 870,378
 447,534
Vesting of performance units 138,374
 76,404
 136,896
Vesting of performance units296,801 592,602 115,596 
Vesting of restricted stock with performance feature 350,063
 40,294
 43,774
Vesting of restricted stock with performance feature553,381 412,465 543,396 
Forfeitures of restricted stock (139,634) (16,795) (51,332)Forfeitures of restricted stock0 (13,807)(58,497)
Purchase of treasury stock (1)
 (342,073) (3,859,403) (16,428,574)
Purchase of treasury stock (1)
(283,047)(11,266,226)(5,886,626)
Common shares outstanding at December 31 177,407,622
 177,345,266
 180,234,388
Common shares outstanding at December 31162,413,660 161,846,525 172,121,491 
 
(1)
Includes 342,073, 147,922 and 151,967 shares, respectively, withheld under the terms of stock-based compensation agreements to provide funds for the payment of payroll and income taxes due at the vesting of share-based awards, as well as other stock repurchases under separate authority from our Board of Directors.

(1)Includes 283,047, 415,466 and 369,255 shares, respectively, withheld under the terms of stock-based compensation agreements to provide funds for the payment of payroll and income taxes due at the vesting of share-based awards, as well as other stock repurchases under separate authority from our Board of Directors.


103

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



In May 2015,November 2019, our Board of Directors approved a $1$1.0 billion share repurchase program, which replaced all existing share repurchase programs authorizing us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions and corporate, regulatory and other relevant considerations. This program may be discontinued at any time by the Board of Directors. As of December 31, 2017,2020, we had remaining authorization to repurchase up to $178.8 millionnot repurchased common stock under this stock repurchase program. In addition, we are authorized by our Board of Directors to repurchase shares in an amount sufficient to offset shares issued under our compensation programs.


During the years ended December 31, 2017, 20162020, 2019 and 2015,2018, we withheld shares of our common stock from certain employees in the amounts of $15.9$7.6 million, $4.7$21.9 million and $6.2$19.6 million,, respectively. These withholdings were made under the terms of restricted stock unit and performance share unit agreements upon vesting, at which time, we concurrently made cash payments to fund payroll and income taxes on behalf of officers and employees who elected to have shares withheld from vested amounts to pay such taxes.




NOTE 16:Other Comprehensive Income (Loss)

NOTE 17:Other Comprehensive Income (Loss)

The components and allocated tax effects of other comprehensive income are as follows:
Before-TaxTax Expense
(Benefit)		After-Tax
 (In thousands)
Year Ended December 31, 2020
Net change in foreign currency translation adjustment$6,226 $1,357 $4,869 
Net unrealized loss on hedging instruments(4,871)(1,228)(3,643)
Net change in pension and other post-retirement benefit obligations(3,461)(923)(2,538)
Other comprehensive loss attributable to HollyFrontier stockholders$(2,106)$(794)$(1,312)
Year Ended December 31, 2019
Net change in foreign currency translation adjustment$13,337 $2,848 $10,489 
Net unrealized loss on hedging instruments(5,349)(1,365)(3,984)
Net change in pension and other post-retirement benefit obligations(7,207)(1,853)(5,354)
Other comprehensive income attributable to HollyFrontier stockholders$781 $(370)$1,151 
Year Ended December 31, 2018
Net change in foreign currency translation adjustment$(38,227)$(8,064)$(30,163)
Net unrealized gain on hedging instruments11,221 2,857 8,364 
Net change in pension and other post-retirement benefit obligations(1,507)(378)(1,129)
Other comprehensive loss attributable to HollyFrontier stockholders$(28,513)$(5,585)$(22,928)
  Before-Tax 
Tax Expense
(Benefit)
 After-Tax
  (In thousands)
Year Ended December 31, 2017      
Net change in foreign currency translation adjustment $22,151
 $7,774
 $14,377
Net unrealized loss on marketable securities (4) (1) (3)
Net unrealized gain on hedging instruments 14,447
 5,613
 8,834
Net change in pension and other post-retirement benefit obligations (5,807) (2,037) (3,770)
Other comprehensive income 30,787
 11,349
 19,438
Less other comprehensive loss attributable to noncontrolling interest (57) —
 (57)
Other comprehensive gain attributable to HollyFrontier stockholders $30,844
 $11,349
 $19,495
       
Year Ended December 31, 2016      
Net unrealized gain on marketable securities $104
 $40
 $64
Net unrealized gain on hedging instruments 25,040
 9,713
 15,327
Net change in other post-retirement benefit obligations (1,113) (431) (682)
Other comprehensive income 24,031
 9,322
 14,709
Less other comprehensive loss attributable to noncontrolling interest (58) —
 (58)
Other comprehensive income attributable to HollyFrontier stockholders $24,089
 $9,322
 $14,767
       
Year Ended December 31, 2015      
Net unrealized gain on marketable securities $38
 $14
 $24
Net unrealized loss on hedging instruments (52,259) (20,282) (31,977)
Net change in other post-retirement benefit obligations 79
 31
 48
Other comprehensive loss (52,142) (20,237) (31,905)
Less other comprehensive income attributable to noncontrolling interest 144
 —
 144
Other comprehensive loss attributable to HollyFrontier stockholders $(52,286) $(20,237) $(32,049)




104

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



The following table presents the income statement line item effects for reclassifications out of accumulated other comprehensive income (“AOCI”):
AOCI ComponentGain (Loss) Reclassified From AOCIIncome Statement Line Item
Years Ended December 31,
202020192018
(In thousands)
Hedging instruments:
Commodity price swaps$(5,168)$(1,799)$(5,093)Sales and other revenues
4,281 22,876 0 Cost of products sold
(1,717)(1,364)(962)Operating expenses
(2,604)19,713 (6,055)
(664)5,027 (1,544)Income tax expense (benefit)
(1,940)14,686 (4,511)Net of tax
Other post-retirement benefit obligations:
Pension obligations422 0 0 Other, net
108 0 0 Income tax expense
314 0 0 Net of tax
Post-retirement healthcare obligations3,564 3,587 3,481 Other, net
909 915 888 Income tax expense
2,655 2,672 2,593 Net of tax
Retirement restoration plan(22)(6)(27)Other, net
(6)(2)(7)Income tax benefit
(16)(4)(20)Net of tax
Total reclassifications for the period$1,013 $17,354 $(1,938)
AOCI Component Gain (Loss) Reclassified From AOCI Income Statement Line Item
  Years Ended December 31,  
  2017 2016 2015  
  (In thousands)  
Marketable securities $—
 $(23) $(51) Interest income
  —
 —
 42
 Other, net
  —
 (23) (9)  
  —
 (9) (3) Income tax benefit
  —
 (14) (6) Net of tax
         
Hedging instruments:        
Commodity price swaps 7,836
 (20,293) 245,819
 Sales and other revenues
  (299) —
 (179,700) Cost of products sold
  (19,244) (21,864) (17,607) Operating expenses
Interest rate swaps 179
 (508) (2,100) Interest expense
  (11,528) (42,665) 46,412
  
  (4,490) (16,387) 18,454
 Income tax expense (benefit)
  (7,038) (26,278) 27,958
 Net of tax
  (74) 320
 1,273
 Noncontrolling interest
  (7,112) (25,958) 29,231
 Net of tax and noncontrolling interest
         
Other post-retirement benefit obligations:        
Post-retirement healthcare obligation 87
 130
 271
 Cost of products sold
  3,012
 2,989
 2,681
 Operating expenses
  382
 363
 347
 Selling, general and administrative expenses
  3,481
 3,482
 3,299
  
  1,347
 1,348
 1,277
 Income tax expense
  2,134
 2,134
 2,022
 Net of tax
         
Retirement restoration plan (17) (15) (20) Selling, general and administrative expenses
  (7) (6) (8) Income tax benefit
  (10) (9) (12) Net of tax
         
Total reclassifications for the period $(4,988) $(23,847) $31,235
  


Accumulated other comprehensive income in the equity section of our consolidated balance sheets includes:
Years Ended December 31,
20202019
 (In thousands)
Foreign currency translation adjustment$2,682 $(2,187)
Unrealized loss on pension obligations(248)(1,733)
Unrealized gain on post-retirement benefit obligations11,310 15,333 
Unrealized gain (loss) on hedging instruments(282)3,361 
Accumulated other comprehensive income$13,462 $14,774 


  Years Ended December 31,
  2017 2016
  (In thousands)
Foreign currency translation adjustment $14,377
 $—
Unrealized loss on pension obligation (654) —
Unrealized gain on post-retirement benefit obligations 16,939
 20,055
Unrealized gain on marketable securities —
 3
Unrealized loss on hedging instruments, net of noncontrolling interest (793) (9,446)
Accumulated other comprehensive income $29,869
 $10,612
NOTE 18:Pension and Post-retirement Plans



NOTE 17:Post-retirement Plans

In connection with ourCertain PCLI acquisition, we agreed to establish employee benefit plans includingemployees are participants in union and non-union pension plans which are closed to new entrants. It is our intention that, effective June 30, 2022, no additional benefits will be accrued under these plans, and the plans will become frozen and employees will be transitioned to a post-retirement healthcaredefined contribution plan. Accordingly, these changes have been accounted for as curtailments and contractual termination benefits. In addition, Sonneborn employees in the Netherlands have a defined benefit pension plan for PCLI employeeswhich was frozen and all plan participants became inactive in 2016. The plan assets are in the form of a third-party insurance contract that were previously coveredis valued based on the assets held by the insurer and insures a value which approximates the accrued benefits related to the plan’s accumulated benefit obligation. At that time, a new plan was established to provide future indexation benefits to participants who had accrued benefits under legacy Suncor plans.the expiring arrangements.



105

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



Our agreement with Suncor also provides that pension assets related to the union and non-union pension plans will be transferred from the Suncor plans to a pension trust established by us and will be computed in accordance with the share purchase agreement, subject to regulatory approval. Our purchase price allocation as of February 1, 2017 included estimates of the amount of pension benefit obligation and the pension assets to be transferred using actuarial estimates. The actual asset transfer to our PCLI pension plan trust will be a cash transfer that is expected to occur in 2018. As of December 31, 2017, the plan asset balance represents a receivable for the pending transfer from the Suncor plans.

The following table sets forth the changes in the benefit obligation and plan assets of our PCLI pension plans for the eleven monthsyears ended December 31, 2017:2020 and 2019, and for our Sonneborn Netherlands plans for the period February 1, 2019 to December 31, 2019 and for the year ended December 31, 2020:

Years Ended December 31,
 February 1, 2017 to December 31, 201720202019
 (In thousands)(In thousands)
Change in plans' benefit obligations  Change in plans' benefit obligations
Pension plans' benefit obligation at acquisition $52,155
Pension plans benefit obligation - beginning of periodPension plans benefit obligation - beginning of period$110,410 $64,435 
Acquisition of SonnebornAcquisition of Sonneborn0 31,686 
Service cost 3,598
Service cost3,929 4,135 
Interest cost 1,979
Interest cost2,772 3,026 
Actuarial loss 4,503
Actuarial loss8,391 5,161 
Benefits paid (966)Benefits paid(1,558)(1,132)
CurtailmentCurtailment(4,078)0 
Contractual termination benefitsContractual termination benefits915 0 
Transfer from other plansTransfer from other plans479 330 
Foreign currency exchange rate changes 2,313
Foreign currency exchange rate changes5,360 2,769 
Pension plans' benefit obligation - end of year $63,582
Pension plans benefit obligation - end of yearPension plans benefit obligation - end of year$126,620 $110,410 
  
Change in pension plans assets  Change in pension plans assets
Fair value of plans assets at acquisition $51,870
Actual return on plans assets 6,182
Fair value of plans assets - beginning of periodFair value of plans assets - beginning of period$105,358 $62,462 
Acquisition of SonnebornAcquisition of Sonneborn0 29,376 
Return on plans assetsReturn on plans assets10,936 7,947 
Employer contributionsEmployer contributions3,487 3,681 
Benefits paid (966)Benefits paid(1,558)(1,132)
Transfer paymentsTransfer payments479 330 
Foreign currency exchange rate changes 2,175
Foreign currency exchange rate changes5,248 2,694 
Fair value of plans assets - end of year $59,261
Fair value of plans assets - end of year$123,950 $105,358 
  
Funded status  Funded status
Under-funded balance $(4,321)Under-funded balance$(2,670)$(5,052)
  
Amounts recognized in consolidated balance sheets  Amounts recognized in consolidated balance sheets
Accrued pension liability $(4,321)
Other long-term liabilitiesOther long-term liabilities$(2,670)$(5,052)
  
Amounts recognized in accumulated other comprehensive income  Amounts recognized in accumulated other comprehensive income
Cumulative actuarial loss $1,162
Cumulative actuarial loss$1,658 $3,155 


The accumulated benefit obligation was $52.8$119.2 million and $100.5 million at December 31, 2017. The2020 and 2019, respectively, which are also the measurement datedates used for our pension plans.

The following tables provide information regarding pension plans was December 31, 2017.with a projected benefit obligation and accumulated benefit obligation in excess of the fair value of plan assets:

December 31,
20202019
(In thousands)
Projected benefit obligation$79,866 $110,410 
Fair value of plan assets$77,035 $105,358 


106

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

December 31,
20202019
(In thousands)
Accumulated benefit obligation$41,654 $36,001 
Fair value of plan assets$39,105 $33,509 

The weighted average assumptions used to determine end of period benefit obligations:obligations for the PCLI plans for the years ended December 31, 2020 and 2019 were discount rates of 2.60% and 3.10%, respectively, and rates of future compensation increases of 3.00% for each year. For the years ended December 31, 2020 and 2019, the weighted average assumption used to determine end of period benefit obligations for Sonneborn were discount rates of 1.10% and 1.50%, respectively.
December 31, 2017
Discount rate3.40%
Rate of future compensation increases3.00%


Net periodic pension expense consisted of the following components:
Years Ended December 31,
202020192018
(In thousands)
Service cost - benefit earned during the period$3,929 $4,135 $4,420 
Interest cost on projected benefit obligations2,772 3,026 2,249 
Expected return on plans assets(4,578)(3,840)(3,464)
Amortization of gain(422)0 0 
Curtailment(137)0 0 
Contractual termination benefits915 0 0 
Net periodic pension expense$2,479 $3,321 $3,205 
  February 1, 2017 to December 31, 2017
  (In thousands)
Service cost - benefit earned during the period $3,598
Interest cost on projected benefit obligations 1,979
Expected return on plans assets (2,841)
Net periodic pension expense $2,736


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



The weighted average assumptions used to determinecomponents, other than service cost, of our net periodic pension expense:expense are recorded in Other, net in our consolidated statements of income.

February 1, 2017 to December 31, 2017
Discount rate3.80%
Rate of future compensation increases3.00%
Expected long-term rate of return on assets5.75%
At December 31, 2020 and 2019, PCLI's pension plans assets were allocated as follows:

Percentage of Plan Assets at Year End
December 31, 2020December 31, 2019
Asset Category
Canadian equities42 %47 %
Fixed income57 %29 %
Real estate and infrastructure0 %14 %
Other1 %9 %
Cash0 %1 %
Total100 %100 %

At December 31, 2020, these fair values are based on Level 2 inputs. See Note 6 for additional information on Level 2 inputs.

The expected long-term rate of return on plan assets is 3.00% for the PCLI pension plans, and is based on a target investment mix of 16% Canadian equities, 75% fixed income, 5% real estate and infrastructure and 4% other.

We expect to contribute $3.5 million to the PCLI and Sonneborn pensions plans in 2021. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.8 million in 2018, $1.2 million in 2019, $1.5 million in 2020, $1.8$2.1 million in 2021, $2.1$2.5 million in 2022, and $14.9$3.0 million in 2023, $3.3 million in 2024, $3.8 million in 2025 and $24.5 million in 2026 to 2027.2030.


Post-retirement Healthcare Plans
We have a post-retirement healthcare and other benefits planplans that isare available to certain of our employees who satisfy certain age and service requirements. This plan isThese plans are unfunded and providesprovide differing levels of healthcare benefits dependent upon hire date and work location. Not all of our employees are covered by this plan at December 31, 2017. In addition, we established a post-retirement healthcare and other benefits plan for our PCLI employees.2020.


107

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

The following table sets forth the changes in the benefit obligation and plan assets of our post-retirement healthcare plans for the years ended December 31, 20172020 and 2016:2019:
Years Ended December 31,
20202019
 (In thousands)
Change in plans' benefit obligation
Post-retirement plans' benefit obligation - beginning of year$31,273 $26,880 
Sonneborn acquisition0 877 
Service cost1,616 1,582 
Interest cost870 1,029 
Benefits paid(1,766)(2,028)
Actuarial loss1,131 2,412 
Foreign currency exchange rate changes354 521 
Post-retirement plans' benefit obligation - end of year$33,478 $31,273 
Change in plan assets
Fair value of plan assets - beginning of year$0 $0 
Employer contributions1,742 2,003 
Participant contributions24 25 
Benefits paid(1,766)(2,028)
Fair value of plan assets - end of year$0 $0 
Funded status
Under-funded balance$(33,478)$(31,273)
Amounts recognized in consolidated balance sheets
Accrued liabilities$(1,946)$(1,817)
Other long-term liabilities(31,532)(29,456)
$(33,478)$(31,273)
Amounts recognized in accumulated other comprehensive income
Cumulative actuarial loss$(1,523)$(197)
Prior service credit18,511 21,992 
Total$16,988 $21,795 
  Years Ended December 31,
  2017 2016
  (In thousands)
Change in plan’s benefit obligation   

Post-retirement plan's benefit obligation - beginning of year $18,992
 $21,201
PCLI acquisition 8,212
 —
Service cost 1,511
 1,294
Interest cost 987
 787
Participant contributions 181
 244
Amendments —
 21
Benefits paid (1,800) (2,171)
Actuarial loss (gain) 1,058
 (2,384)
Foreign currency exchange rate changes 358
 —
Post-retirement plans' benefit obligation - end of year $29,499
 $18,992
     
Change in plan assets    
Fair value of plan assets - beginning of year $—
 $—
Employer contributions 1,542
 1,927
Participant contributions 258
 244
Benefits paid (1,800) (2,171)
Fair value of plan assets - end of year $—
 $—
     
Funded status    
Under-funded balance $(29,499) $(18,992)
     
Amounts recognized in consolidated balance sheets    
Accrued post-retirement liability $(29,499) $(18,992)
     
Amounts recognized in accumulated other comprehensive income    
Cumulative actuarial (loss) gain $(287) $771
Prior service credit 28,953
 32,434
Total $28,666
 $33,205



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.9$1.9 million in 2018; $1.6 million in 2019; $1.6 million in 2020; $1.7 million in 2021; $1.7$1.9 million in 2022; $1.9 million in 2023; $1.9 million in 2024; $1.9 million in 2025; and $8.2$9.2 million in 20232026 through 2027.2030.


The weighted average assumptions used to determine end of period benefit obligations:
December 31,
20202019
Discount rate1.88%-2.60%2.94% - 3.20%
Current health care trend rate5.50%-6.00%6.00% - 6.50%
Ultimate health care trend rate4.50%-5.00%4.50% - 5.00%
Year rate reaches ultimate trend rate2022-20232022 - 2023
108

  December 31, 2017 December 31, 2016
  HFC PCLI HFC
       
Discount rate 3.35% 3.40% 3.75%
Current health care trend rate 7.00% 6.50% 7.00%
Ultimate health care trend rate 5.00% 5.00% 5.00%
Year rate reaches ultimate trend rate 2028
 2022
 2030
HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

Net periodic post-retirement credit consisted of the following components:
Years Ended December 31,
202020192018
 (In thousands)
Service cost – benefit earned during the year$1,616 $1,582 $1,648 
Interest cost on projected benefit obligations870 1,029 938 
Amortization of prior service credit(3,481)(3,481)(3,481)
Amortization of gain(83)(106)0 
Net periodic post-retirement credit$(1,078)$(976)$(895)
  Years Ended December 31,
  2017 2016 2015
  (In thousands)
Service cost – benefit earned during the year $1,511
 $1,294
 $1,694
Interest cost on projected benefit obligations 987
 787
 819
Amortization of prior service credit (3,481) (3,482) (3,482)
Amortization of net loss —
 —
 183
Net periodic post-retirement credit $(983) $(1,401) $(786)


The components, other than service cost, of our net periodic post-retirement credit are recorded in Other, net in our consolidated statements of income. Prior service credits are amortized over the average remaining effective period to obtain full benefit eligibility for participants.

Assumed health care cost trend rates have an effect on the amounts reported for the post-retirement health care benefit plan. The weighted average assumptions used to determine net periodic benefit expense follow:
  Years Ended December 31,
  2017 2016 2015
  HFC PCLI HFC
         
Discount rate 3.75% 3.80% 3.90% 3.60%
Current health care trend rate 7.00% 6.50% 8.00% 8.00%
Ultimate health care trend rate 5.00% 5.00% 5.00% 5.00%
Year rate reaches ultimate trend rate 2030
 2022
 2041
 2042

The effect of a 1% change in health care cost trend rates is as follows:
  1% Point Increase 1% Point Decrease
  (In thousands)
Service cost $175
 $(146)
Interest cost $48
 $(42)
Year-end accumulated post-retirement benefit obligation $1,393
 $(1,204)


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



Retirement Restoration Plan
We have an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. We expensed $0.1$0.1 million, $0.1 million and $0.1 million for each of the years ended December 31, 2017, 20162020, 2019 and 2015, respectively,2018 in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $2.7$2.5 million and $2.7$2.4 million at December 31, 20172020 and 2016,2019, respectively. As of December 31, 2017,2020, the projected benefit obligation under this plan was $2.7 million.$2.5 million. Annual benefit payments of $0.2$0.2 million are expected to be paid through 2027,2030, which reflect expected future service.


Defined Contribution PlanPlans
We have a defined contribution “401(k)” planplans that coverscover substantially all U.S. employees.qualified employees in the U.S, Canada and the Netherlands. Our contributions are based on an employee's eligible compensation and years of service. We also partially match our employees’ contributions. We expensed $17.6expensed $43.3 million,, $17.5 $30.3 million and $17.2 million for the years ended December 31, 2017, 2016 and 2015, respectively, in connection with this plan.


NOTE 18:Lease Commitments

We lease certain office and storage facilities, rail cars and other equipment under long-term operating leases, most of which contain renewal options. At December 31, 2017, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows:
  (In thousands)
2018 $82,345
2019 74,987
2020 70,654
2021 58,571
2022 51,019
Thereafter 88,626
Total $426,202

Rental expense charged to operations was $95.7 million, $93.2 million and $107.3$19.1 million for the years ended December 31, 2017, 20162020, 2019 and 2015, respectively.2018, respectively, in connection with these plans.




NOTE 19:Contingencies and Contractual Commitments

NOTE 19:Contingencies and Contractual Commitments

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


We filed a business interruption claim with our insurance carriers related to a loss at our Woods Cross Refinery that occurred in the first quarter 2018. During the year ended December 31, 2020, we reached a final settlement agreement regarding the amounts owed to us pursuant to our business interruption coverage, and we recognized a gain of $81.0 million, which is reflected in our Corporate and Other segment.

During 2017, 2018 and 2019, the EPA granted the Cheyenne Refinery and Woods Cross Refinery each a one-year small refinery exemption from the RFS program requirements for the 2016, 2017 and 2018, respectively, calendar years. As a result, the Cheyenne Refinery’s and Woods Cross Refinery’s gasoline and diesel production are not subject to the RVO for the respective years. Upon each exemption granted, we increased our inventory of RINs and reduced our cost of products sold.

109

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued


Various subsidiaries of HollyFrontier are currently intervenors in three lawsuits brought by renewable fuel interest groups against the EPA in federal courts alleging violations of the RFS under the Clean Air Act and challenging the EPA’s handling of small refinery exemptions. We intervened to vigorously defend the EPA’s position on small refinery exemptions because we believe the EPA correctly applied applicable law to the matters at issue. On January 24, 2020, in the first of these lawsuits, the U.S. Court of Appeals for the Tenth Circuit vacated the small refinery exemptions granted to two of our refineries for 2016 and remanded the case to the EPA for further proceedings. On April 15, 2020, the Tenth Circuit entered its mandate, remanding the matter back to the EPA. On September 4, 2020, various subsidiaries of HollyFrontier filed a Petition for a Writ of Certiorari with the U.S. Supreme Court appealing the Tenth Circuit decision. On January 8, 2021, the U.S. Supreme Court granted HollyFrontier's petition. We anticipate a decision from the Supreme Court in June 2021. We expect that we will not know what steps the EPA will take with respect to our 2016 small refinery exemptions, or how the case will impact future small refinery exemptions until after the Supreme Court's decision in this matter. The second lawsuit is before the Tenth Circuit. The matter is fully briefed and remains pending before that court. The third lawsuit is before the DC Circuit. Briefing of the issues before the court commenced on December 7, 2020; however, in light of the Supreme Court's decision to hear HollyFrontier's appeal of the Tenth Circuit decision, this case was stayed pending a decision from the Supreme Court. In December 2020, various subsidiaries of HollyFrontier also filed a petition for review in the DC Circuit challenging the EPA's denial of small refinery exemption petitions for years prior to 2016. The petition was consolidated with petitions from eight other refining companies challenging the same decision. In light of the Supreme Court's decision to hear HollyFrontier's appeal of the Tenth Circuit decision, this case was stayed pending a decision from the Supreme Court. We are unable to estimate the costs we may incur, if any, at this time. It is too early to assess how the matter currently on appeal to the U.S. Supreme Court will impact future small refinery exemptions or whether the remaining cases are expected to have any impact on us.

We have been party to multiple proceedings before the Federal Energy Regulatory Commission (“FERC”) challenging the rates charged by SFPP, L.P. (“SFPP”) on its East Line pipeline facilities from El Paso, Texas to Phoenix, Arizona. In March 2018, FERC ruled that SFPP, as a master limited partnership, was prohibited from including an allowance for investor income taxes in the cost of service underlying its East Line rates. We reached a negotiated settlement with SFPP that provides for a payment to us of $51.5 million. FERC approved the settlement on December 31, 2020 subject to a rehearing period that resulted in a settlement effective date of February 2, 2021. Under the terms of the settlement agreement, SFPP made the $51.5 million payment to us on February 10, 2021. As of December 31, 2020, we had no enforceable right to collect any of the settlement. Accordingly, recognition of a gain occurred when the uncertainties were resolved, and we held an enforceable right to collect on February 2, 2021.

Contractual Commitments
We have various long-term agreements (entered in the normal course of business) to purchase crude oil, natural gas, feedstocks and other resources to ensure we have adequate supplies to operate our refineries. The substantial majority of our purchase obligations are based on market prices or rates. These contracts expire in 20192021 through 2033.2025.


We also have long-term agreements with third parties for the transportation and storage of crude oil, natural gas and feedstocks to our refineries and for terminal and storage services that expire in 20182021 through 2033.2039. At December 31, 2017,2020, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:
(In thousands)
2021$129,661 
2022113,288 
2023113,360 
2024112,884 
2025113,669 
Thereafter580,889 
Total$1,163,751 
  (In thousands)
2018 $148,716
2019 132,547
2020 119,639
2021 107,400
2022 102,884
Thereafter 857,454
Total $1,468,640


Transportation and storage costs incurred under these agreements totaled $140.5$139.0 million, $135.1$144.8 million and $137.7$143.3 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively. These amounts do not include contractual commitments under our long-term transportation agreements with HEP, as all transactions with HEP are eliminated in these consolidated financial statements.



110

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued




We have a crude oil supply contract that requires the supplier to deliver a specified volume of crude oil or pay a shortfall fee for the difference in the actual barrels delivered to us less the specified barrels per the supply contract. For the contract year ended August 31, 2017, the actual number of barrels delivered to us was substantially less than the specified barrels, and we recorded a reduction to cost of goods sold and accumulated a shortfall fee receivable of $26.0 million during this period. In September 2017, the supplier notified us they are disputing the shortfall fee owed and in October 2017 notified us of their demand for arbitration. We offset the receivable with payments of invoices for deliveries of crude oil received subsequent to August 31, 2017, which is permitted under the supply contract. We believe the disputes and claims made by the supplier are without merit.

In March, 2006, a subsidiary of ours sold the assets of Montana Refining Company under an Asset Purchase Agreement (“APA”). Calumet Montana Refining LLC, the current owner of the assets, has submitted requests for reimbursement of approximately $20.0 million pursuant to contractual indemnity provisions under the APA for various costs incurred, as well as additional claims related to environmental matters. We have rejected most of the claims for payment, and this matter is scheduled for arbitration beginning in July 2018. We have accrued the costs we believe are owed pursuant to the APA, and we estimate that any reasonably possible losses beyond the amounts accrued are not material.


NOTE 20:Segment Information

NOTE 20:Segment Information
Effective fourth quarter of 2017, we revised our reportable segments to align with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, our Tulsa Refineries’ lubricants operations, previously reported in the Refining segment, are now combined with the operations of our Petro-Canada Lubricants business (acquired February 1, 2017) and reported in the Lubricants and Specialty Products segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation.


Our operations are organized into three3 reportable segments,segments: Refining, Lubricants and Specialty Products and HEP. Our operations that are not included in the Refining, Lubricants and Specialty Products and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Eliminations. Corporate and Other and Eliminations are aggregated and presented under the Corporate, Other and Eliminations column.


The Refining segment represents the operations of the El Dorado, Tulsa, Navajo Cheyenne and Woods Cross Refineries and HFC Asphalt (aggregated as a reportable segment). Refining activities involve the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel. These petroleum products are primarily marketed in the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States. HFC Asphalt operates various asphalt terminals in Arizona, New Mexico and Oklahoma. The Refining segment also included the operations of the Cheyenne Refinery until it permanently ceased petroleum refining operations during the third quarter of 2020.


HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued



The Lubricants and Specialty Products segment involves PCLI’s production operations, located in Mississauga, Ontario, that includes lubricant products such as base oils, white oils, specialty products and finished lubricants, and the operations of our Petro-Canada Lubricants business that includes the marketing of products to both retail and wholesale outlets through a global sales network with locations in Canada, the United States, Europe and China. Additionally, the Lubricants and Specialty Products segment includes specialty lubricant products produced at our Tulsa Refineries that are marketed throughout North America and are distributed in Central and South America and Red Giant Oil, one of the largest suppliers of locomotive engine oil in North America. Also, effective with our acquisition that closed February 1, 2019, the Lubricants and Specialty Products segment includes Sonneborn, a producer of specialty hydrocarbon chemicals such as white oils, petrolatums and waxes with manufacturing facilities in the United States and Europe..


The HEP segment includes all of the operations of HEP, which owns and operates logistics and refinery assets consisting of petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and refinery processing units in the Mid-Continent, Southwest and Rocky Mountain geographic regions of the United States. The HEP segment also includes a 75% ownership interest in UNEV (a consolidated subsidiary of HEP) and 50% ownership interest in each of the Osage Pipeline, and the Cheyenne Pipeline.Pipeline and Cushing Connect. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations. Due to certain basis differences, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.


111

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued

The accounting policies for our segments are the same as those described in the summary of significant accounting policies (see Note 1).


RefiningLubricants and Specialty ProductsHEP
Corporate, Other and Eliminations (2)
Consolidated
Total
 (In thousands)
Year Ended December 31, 2020
Sales and other revenues:
Revenues from external customers$9,286,658 $1,792,745 $98,039 $6,201 $11,183,643 
Intersegment revenues252,531 10,465 399,809 (662,805)0 
$9,539,189 $1,803,210 $497,848 $(656,604)$11,183,643 
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment)$8,439,680 $1,271,287 $0 $(552,162)$9,158,805 
Lower of cost or market inventory valuation adjustment$82,214 $0 $0 $(3,715)$78,499 
Operating expenses$988,045 $216,068 $147,692 $(51,528)$1,300,277 
Selling, general and administrative expenses$127,298 $157,816 $9,989 $18,497 $313,600 
Depreciation and amortization$324,617 $80,656 $95,445 $20,194 $520,912 
Goodwill and long-lived asset impairments (1)
$241,760 $286,575 $16,958 $0 $545,293 
Income (loss) from operations$(664,425)$(209,192)$227,764 $(87,890)$(733,743)
Earnings of equity method investments$0 $0 $6,647 $0 $6,647 
Capital expenditures$152,726 $32,473 $59,283 $85,678 $330,160 
Total assets$6,203,847 $1,864,313 $2,198,478 $1,240,226 $11,506,864 
112
  Refining Lubricants and Specialty Products HEP Corporate, Other and Eliminations Consolidated
Total
  (In thousands)
Year Ended December 31, 2017          
Sales and other revenues:          
Revenues from external customers $12,579,672
 $1,594,036
 $77,225
 $366
 $14,251,299
Intersegment revenues 338,390
 —
 377,137
 (715,527) —
  $12,918,062
 $1,594,036
 $454,362
 $(715,161) $14,251,299
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment) $11,009,345
 $1,093,984
 $—
 $(635,530) $11,467,799
Lower of cost or market inventory valuation adjustment (107,479) (1,206) —
 —
 (108,685)
Operating expenses $1,006,675
 $222,461
 $137,605
 $(72,507) $1,294,234
Selling, general and administrative expenses $103,067
 $105,112
 $14,323
 $42,372
 $264,874
Depreciation and amortization $289,434
 $31,894
 $77,660
 $10,949
 $409,937
Asset impairment $19,247
 $—
 $—
 $—
 $19,247
Income (loss) from operations $597,773
 $141,791
 $224,774
 $(60,445) $903,893
Earnings of equity method investments $—
 $—
 $12,510
 $—
 $12,510
Capital expenditures $176,533
 $31,464
 $44,810
 $19,452
 $272,259
Total assets $6,474,666
 $1,610,472
 $2,191,984
 $415,032
 $10,692,154



HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



RefiningLubricants and Specialty ProductsHEPCorporate, Other and EliminationsConsolidated
Total
(In thousands)
Year Ended December 31, 2019
Sales and other revenues:
Revenues from external customers$15,284,110 $2,081,221 $121,027 $220 $17,486,578 
Intersegment revenues312,678 11,307 411,750 (735,735)0 
$15,596,788 $2,092,528 $532,777 $(735,515)$17,486,578 
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment)$12,980,506 $1,580,036 $0 $(642,158)$13,918,384 
Lower of cost or market inventory valuation adjustment$(119,775)$0 $0 $0 $(119,775)
Operating expenses$1,095,488 $231,523 $161,996 $(94,955)$1,394,052 
Selling, general and administrative expenses$120,518 $168,595 $10,251 $54,872 $354,236 
Depreciation and amortization$309,932 $88,781 $96,706 $14,506 $509,925 
Goodwill impairment$0 $152,712 $0 $0 $152,712 
Income (loss) from operations$1,210,119 $(129,119)$263,824 $(67,780)$1,277,044 
Earnings of equity method investments$0 $0 $5,180 $0 $5,180 
Capital expenditures$199,002 $40,997 $30,112 $23,652 $293,763 
Total assets$7,189,094 $2,223,418 $2,205,437 $546,892 $12,164,841 
Year Ended December 31, 2018
Sales and other revenues:
Revenues from external customers$15,806,304 $1,799,506 $108,412 $444 $17,714,666 
Intersegment revenues370,259 13,197 397,808 (781,264)0 
$16,176,563 $1,812,703 $506,220 $(780,820)$17,714,666 
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment)$13,250,849 $1,381,540 $0 $(691,607)$13,940,782 
Lower of cost or market inventory valuation adjustment$136,305 $0 $0 $0 $136,305 
Operating expenses$1,055,209 $167,820 $146,430 $(83,621)$1,285,838 
Selling, general and administrative expenses$113,641 $143,750 $11,041 $21,992 $290,424 
Depreciation and amortization$284,439 $43,255 $98,492 $11,138 $437,324 
Income (loss) from operations$1,336,120 $76,338 $250,257 $(38,722)$1,623,993 
Earnings of equity method investments$0 $0 $5,825 $0 $5,825 
Capital expenditures$202,791 $37,448 $54,141 $16,649 $311,029 
Total assets$6,465,155 $1,506,209 $2,142,027 $881,210 $10,994,601 


  Refining Lubricants and Specialty Products HEP Corporate, Other and Eliminations 
Consolidated
Total
  (In thousands)
Year Ended December 31, 2016          
Sales and other revenues:          
Revenues from external customers $10,002,831
 $464,359
 $68,927
 $(417) $10,535,700
Intersegment revenues 317,884
 —
 333,116
 (651,000) —
  $10,320,715
 $464,359
 $402,043
 $(651,417) $10,535,700
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment) $9,003,505
 $377,136
 $—
 $(614,714) $8,765,927
Lower of cost or market inventory valuation adjustment $(287,848) $(4,090) $—
 $—
 $(291,938)
Operating expenses $909,724
 $13,867
 $123,984
 $(28,736) $1,018,839
Selling, general and administrative expenses $92,297
 $2,899
 $12,532
 $17,920
 $125,648
Depreciation and amortization $281,701
 $620
 $68,811
 $11,895
 $363,027
Goodwill and asset impairment $654,084
 $—
 $—
 $—
 $654,084
Income (loss) from operations $(332,748) $73,927
 $196,716
 $(37,782) $(99,887)
Earnings of equity method investments $—
 $—
 $14,213
 $—
 $14,213
Capital expenditures $357,407
 $5,708
 $107,595
 $9,080
 $479,790
Total assets $6,048,091
 $465,715
 $1,920,487
 $1,001,368
 $9,435,661
           
Year Ended December 31, 2015          
Sales and other revenues:          
Revenues from external customers $12,677,901
 $493,282
 $66,654
 $83
 $13,237,920
Intersegment revenues 361,211
 —
 292,221
 (653,432) —
  $13,039,112
 $493,282
 $358,875
 $(653,349) $13,237,920
Cost of products sold (exclusive of lower of cost or market inventory valuation adjustment) $10,472,268
 $414,553
 $—
 $(647,603) $10,239,218
Lower of cost or market inventory valuation adjustment $225,736
 $1,243
 $—
 $—
 $226,979
Operating expenses $940,629
 $14,042
 $105,554
 $148
 $1,060,373
Selling, general and administrative expenses $91,279
 $2,615
 $12,556
 $14,396
 $120,846
Depreciation and amortization $273,091
 $254
 $61,690
 $11,116
 $346,151
Income (loss) from operations $1,036,109
 $60,575
 $179,075
 $(31,406) $1,244,353
Earnings (loss) of equity method investments $—
 $—
 $4,803
 $(8,541) $(3,738)
Capital expenditures $461,326
 $7,685
 $193,121
 $14,023
 $676,155
Total assets $6,286,154
 $320,510
 $1,802,970
 $(21,335) $8,388,299


NOTE 21:Significant Customers

We have two significant customers (Shell Oil and Sinclair), each of which has historically accounted for approximately 10%(1) The results of our annual revenues. Shell Oil accounted for $1,317.9 million (9%), $1,048.2 million (10%) and $1,252.6 million (9%) for the years ended December 31, 2017, 2016 and 2015, respectively, and Sinclair accounted for $1,135.7 million (8%), $927.0 million (9%) and $1,104.9 million (8%) of our revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

Non-U.S. sales represented 7% of our revenuesHEP reportable segment for the year ended December 31, 2017. The Canadian market represents2020 include a long-lived asset impairment charge attributed to HEP’s logistics assets at our largest concentrationCheyenne Refinery.

(2) For the year ended December 31, 2020, Corporate and Other includes $3.9 million of foreign salesoperating expenses and accounted for 4%$65.1 million of capital expenditures related to the construction of our revenuesrenewable diesel units. Also, for the year ended December 31, 2017.2020, Corporate and Other includes $14.0 million of decommissioning and other shutdown costs related to our Cheyenne Refinery. In addition, for the year ended December 31, 2020, Corporate and Other includes $11.4 million in other operating costs related to our Cheyenne facility.




113

HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS
Continued



NOTE 22:Quarterly Information (Unaudited)

NOTE 21:Quarterly Information (Unaudited)

First QuarterSecond QuarterThird QuarterFourth QuarterYear
 First Quarter Second Quarter Third Quarter Fourth Quarter Year(In thousands, except per share data)
 (In thousands, except per share data)
Year Ended December 31, 2017          
Year Ended December 31, 2020Year Ended December 31, 2020
Sales and other revenues $3,080,483
 $3,458,864
 $3,719,247
 $3,992,705
 $14,251,299
Sales and other revenues$3,400,545 $2,062,930 $2,819,400 $2,900,768 $11,183,643 
Operating costs and expenses $3,113,207
 $3,337,179
 $3,269,967
 $3,627,053
 $13,347,406
Operating costs and expenses$3,810,847 $2,252,906 $2,846,618 $3,007,015 $11,917,386 
Income (loss) from operations (1,2)
 $(32,724) $121,685
 $449,280
 $365,652
 $903,893
Loss from operations (1) (2)
Loss from operations (1) (2)
$(410,302)$(189,976)$(27,218)$(106,247)$(733,743)
Income (loss) before income taxes $(54,571) $106,069
 $446,103
 $371,262
 $868,863
Income (loss) before income taxes$(455,452)$(181,318)$27,918 $(138,194)$(747,046)
Net income (loss) attributable to HollyFrontier stockholders $(45,468) $57,767
 $272,014
 $521,082
 $805,395
Net income (loss) per share attributable to HollyFrontier stockholders - basic $(0.26) $0.33
 $1.53
 $2.94
 $4.54
Net income (loss) per share attributable to HollyFrontier stockholders - diluted $(0.26) $0.33
 $1.53
 $2.92
 $4.52
Net loss attributable to HollyFrontier stockholdersNet loss attributable to HollyFrontier stockholders$(304,623)$(176,677)$(2,401)$(117,747)$(601,448)
Net loss per share - basicNet loss per share - basic$(1.88)$(1.09)$(0.01)$(0.73)$(3.72)
Net loss per share - dilutedNet loss per share - diluted$(1.88)$(1.09)$(0.01)$(0.73)$(3.72)
Dividends per common share $0.33
 $0.33
 $0.33
 $0.33
 $1.32
Dividends per common share$0.35 $0.35 $0.35 $0.35 $1.40 
Average number of shares of common stock outstanding:          Average number of shares of common stock outstanding:
Basic 176,210
 176,147
 176,149
 176,265
 176,174
Basic161,873 161,889 162,015 162,151 161,983 
Diluted 176,210
 176,302
 176,530
 177,457
 177,196
Diluted161,873 161,889 162,015 162,151 161,983 
          
Year Ended December 31, 2016          
Year Ended December 31, 2019Year Ended December 31, 2019
Sales and other revenues $2,018,724
 $2,714,638
 $2,847,270
 $2,955,068
 $10,535,700
Sales and other revenues$3,897,247 $4,782,615 $4,424,828 $4,381,888 $17,486,578 
Operating costs and expenses $1,935,126
 $3,135,180
 $2,722,505
 $2,842,776
 $10,635,587
Operating costs and expenses$3,507,906 $4,450,874 $3,998,049 $4,252,705 $16,209,534 
Income (loss) from operations (3) (4)
 $83,598
 $(420,542) $124,765
 $112,292
 $(99,887)
Income (loss) before income taxes $65,698
 $(430,515) $109,867
 $83,416
 $(171,534)
Net income (loss) attributable to HollyFrontier stockholders $21,253
 $(409,368) $74,497
 $53,165
 $(260,453)
Net income (loss) per share attributable to HollyFrontier stockholders - basic $0.12
 $(2.33) $0.42
 $0.30
 $(1.48)
Net income (loss) per share attributable to HollyFrontier stockholders - diluted $0.12
 $(2.33) $0.42
 $0.30
 $(1.48)
Income from operations (3)(4)
Income from operations (3)(4)
$389,341 $331,741 $426,779 $129,183 $1,277,044 
Income before income taxesIncome before income taxes$363,991 $306,153 $401,001 $100,359 $1,171,504 
Net income attributable to HollyFrontier stockholdersNet income attributable to HollyFrontier stockholders$253,055 $196,915 $261,813 $60,605 $772,388 
Net income per share - basicNet income per share - basic$1.48 $1.16 $1.60 $0.38 $4.64 
Net income per share - dilutedNet income per share - diluted$1.47 $1.15 $1.58 $0.37 $4.61 
Dividends per common share $0.33
 $0.33
 $0.33
 $0.33
 $1.32
Dividends per common share$0.33 $0.33 $0.33 $0.35 $1.34 
Average number of shares of common stock outstanding:          Average number of shares of common stock outstanding:
Basic 176,737
 175,865
 175,871
 175,936
 176,101
Basic170,851 169,356 163,676 161,398 166,287 
Diluted 176,784
 175,865
 175,993
 176,137
 176,101
Diluted172,239 170,547 165,011 162,898 167,385 


(1) For 2017, income2020, loss from operations reflects non-cash lower of cost or market inventory valuation charges of $11.8 million and $84.0$560.5 million for the first quarter, and second quarters, respectively, and a reductionbenefits of $111.1$269.9 million, $62.8 million and $93.4 $149.2 million for the second, third and fourth quarters, respectively.


(2) For 2017, income2020, loss from operations reflects non-cash long-lived asset impairment charges of $23.2$436.9 million in the second quarter and goodwill and long-lived asset impairment charges of $108.4 million in the fourth quarter.


(3) For 2016,2019, income from operations reflects non-cash lower of cost or market inventory valuation reductionsbenefits of $56.1 million and $138.5$232.3 million for the first quarter, and second quarters, respectively,charges of $47.8 million, $34.1 million and increases of $0.3$30.7 million for the second, third quarter and a reduction of $97.7 million for the fourth quarter.quarters, respectively.


(4) For 2016,2019, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $309.3$152.7 million and $344.8 million , respectively, in the second quarter.



114

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 accountants on matters involving accounting and financial disclosure.




Item 9A. Controls and Procedures


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 at the reasonable assurance level as of December 31, 2017.2020.


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


See Item 8 for “Management's Report on its Assessment of the Company's Internal Control Over Financial Reporting” and “Report of the Independent Registered Public Accounting Firm.”




Item 9B. Other Information


There have been no events that occurred in the fourth quarter of 20172020 that would need to be reported on Form 8-K that have not previously been reported.




PART III




Item 10. Directors, Executive Officers and Corporate Governance


The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 9, 201812, 2021 and is incorporated herein by reference.




Item 11. Executive Compensation


The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 9, 201812, 2021 and is incorporated herein by reference.




Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 9, 201812, 2021 and is incorporated herein by reference.




115
Table of Content

Item 13. Certain Relationships and Related Transactions, and Director Independence


The information required by Items 404 and 407(a) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 9, 201812, 2021 and is incorporated herein by reference.




Item 14. Principal Accounting Fees and Services


The information required by Item 9(e) of Schedule 14A in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 9, 201812, 2021 and is incorporated herein by reference.




PART IV


Item 15. Exhibits, Financial Statement Schedules


(a)    Documents filed as part of this report


(1)    Index to Consolidated Financial Statements
Page in Form 10-K
Report of Independent Registered Public Accounting Firm
5766
Consolidated Balance Sheets at December 31, 20172020 and 20162019
5869
Consolidated Statements of Income for the years ended December 31, 2017, 20162020, 2019 and 20152018
5970
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 20162020, 2019 and 20152018
6071
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 20162020, 2019 and 20152018
6172
Consolidated Statements of Equity for the years ended December 31, 2017, 20162020, 2019 and 20152018
6273
Notes to Consolidated Financial Statements
6374


(2)    Index to Consolidated Financial Statement Schedules


All schedules are omitted since the required information is not present or is 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


The Exhibit Index on pages 102 to 107 of this Annual Report on Form 10-K lists the exhibits that are filedFiled or furnished, as applicable, as part of this Annual Report on Form 10-K.10-K are the following exhibits:






116
Table of Content

HOLLYFRONTIER CORPORATION
INDEX TO EXHIBITS

Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K

Exhibit NumberDescription
Exhibit Number2.1†Description
2.1
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's Current Report on Form 8-K filed October 21, 2009, File No. 1-03876).
2.22.2†
Amendment No. 1 to Asset Sale and Purchase Agreement, dated December 1, 2009, between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed December 7, 2009, File No. 1-03876).
2.32.3†
Asset Sale and Purchase Agreement, dated April 15, 2009, between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed April 16, 2009, File No. 1-03876).
2.42.4†
Share Purchase Agreement, dated October 29, 2016, by and between Suncor Energy Inc. and 9952110 Canada Inc. (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed October 31, 2016, File No. 1-03876).
2.52.5†
Equity RestructuringPurchase Agreement, dated as of October 18, 2017,November 12, 2018, by and between HEP LogisticsSonneborn Holdings, L.P., Sonneborn Co-Op LLC, Sonneborn Coöperatief U.A. and Holly Energy Partners, L.P.HollyFrontier LSP Holdings LLC (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed October 19, 2017,November 13, 2018, File No. 1-03846).
2.6
Waiver and Amendment to Equity Purchase Agreement, dated January 31, 2019, by and between Sonneborn Holdings, L.P., Sonneborn Co-Op LLC, Sonneborn Coöperatief U.A. and HollyFrontier LSP Holdings LLC (incorporated by reference to Exhibit 2.7 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2018. File No. 1-03876).
3.1
Amended and Restated Certificate of Incorporation of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).
3.23.2*
Amended and Restated Bylaws of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K filed February 20, 2014, File No. 1-03876).
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 Holly Energy Partners, L.P.'s Current Report on Form 8-K filed July 19, 2016, File Number 1-32225).
4.2
First Supplemental Indenture, dated November 2, 2016, among Woods Cross Operating LLC, Holly Energy Partners, L.P., and Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016, File Number 1-32225).
4.3
Second Supplemental Indenture, dated July 26, 2017, by and among Holly Energy Holdings LLC, HEP Cheyenne Shortline LLC, Holly Energy Partners, L.P., 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. 1-03876).
4.4
Indenture, dated March 22, 2016, between HollyFrontier Corporation and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed March 22, 2016, File No. 1-03876).
4.54.2
Supplemental Indenture, dated March 22, 2016, between HollyFrontier Corporation and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Registrant's Current Report on Form 8-K filed March 22, 2016, File No. 1-03876).
10.14.3
Second Supplemental Indenture, dated as of September 28, 2020, between HollyFrontier Corporation and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Registrant’s Current Report on Form 8-K dated September 28, 2020, File No. 1-03876).
4.4
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 Holly Energy Partners, L.P.’s Current Report on Form 8-K filed February 4, 2020, File No. 1-32225).
4.5*
10.1
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 Logistics Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed June 5, 2009, File No. 1-32225).



117
Table of Content
10.2Exhibit NumberDescription
10.2
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 Logistics Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.4 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

Table of Content

Exhibit Number10.4Description
10.3
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 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
10.4
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 Holly Energy Partners L.P.'s Current Report on Form 8-K filed August 6, 2009, File No. 1-32225).
10.5
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 10.7 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
10.6
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 10.8 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
10.7
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 Holly Energy Partners L.P.'s Current Report on Form 8-K filed August 6, 2009, File No. 1-32225).
10.810.5
Third Amended and Restated Crude Pipelines and Tankage Agreement, dated 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 filed March 16, 2015, File No. 1-03876).
10.910.6
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 10.310.1 of Registrant's Current Report on Form 8-K filed February 22, 2016,10-Q for the quarterly period ended March 31, 2019, File No. 1-03876).
10.1010.7
Second Amendment to Third Amended and Restated ThroughputCrude Pipelines and Tankage Agreement (Tucson Terminal), dated September 19, 2013, effective June 1, 2013,as of May 26, 2020, by and among HollyFrontier Navajo Refining LLC, HollyFrontier Woods Cross Refining LLC, HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C. and Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.4 of Registrant'sRegistrant’s Quarterly Report on Form 10-Q for the quarterly period ended SeptemberJune 30, 2013,2020, File No. 1-03876).
10.11*10.8
EighteenthThird 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 datedFebruary 11, 2021, File No. 1-03876).
10.9
Twenty-First Amended and Restated Omnibus Agreement, datedentered into as of February 8, 2020, effective as of January 19, 2018, effective December 8, 2017, 1, 2021, by and amongbetween HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries.subsidiaries (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed February 11, 2021, File No. 1-03876).
10.1210.10
Senior Unsecured 5-Year Revolving Credit Agreement, dated July 1, 2014, among HollyFrontier Corporation, as borrower, Union Bank, N. A. as administrative agent, and each of the financial institutions party thereto as lenders (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 8, 2014, File No. 1-03876).
10.11
10.13
First Amendment to Senior Unsecured 5-Year Revolving Credit Agreement, dated as of February 16, 2017, among HollyFrontier Corporation, as borrower, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed February 21, 2017, File No. 1-03876).
10.1410.12
Release of Subsidiary Guarantee, dated December 29, 2015, by and among HollyFrontier Corporation and Union Bank, N.A. (incorporated by reference to Exhibit 10.40 of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, File No. 1-03876).
10.15
Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (“the Agreement”) and First Amendment to the Agreement dated September 18, 2000, Second Amendment to the Agreement dated September 21, 2000, Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment to the Agreement dated February 22, 2001, Fifth Amendment to the Agreement dated August 14, 2001, Sixth Amendment to the Agreement dated November 5, 2001, Seventh Amendment to the Agreement dated April 22, 2002, Eighth Amendment to the Agreement date d May 30, 2003, Ninth Amendment to the Agreement dated May 25, 2004, Tenth Amendment to the Agreement dated May 3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006, Twelfth Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the Agreement dated September 30, 2007, Fourteenth Amendment to the Agreement dated May 1, 2008 and Fifteenth Amendment to the Agreement dated May 28, 2008 (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2008, File No. 1-07627).
Table of Content


Exhibit Number10.13Description
10.16
Seventeenth Amendment, dated August 27, 2013, to the Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company (now HollyFrontier Refining & Marketing LLC, as successor-by-merger to Frontier Oil and Refining Company) and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013, File No. 1-03876).
10.17
Master Crude Oil Purchase and Sale Contract, dated November 1, 2010, among BNP Paribas Energy Trading GP, BNP Paribas Energy Trading Canada Corp., Frontier Oil and Refining Company and Frontier Oil Corporation (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627).
10.18
Guaranty, dated November 1, 2010, by Frontier Oil Corporation in favor of BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp. (incorporated by reference to Exhibit 10.2 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627).
10.19
Amended and Restated Limited Liability Company Agreement of HEP UNEV Holdings LLC, dated July 12, 2012, among HEP UNEV Holdings LLC, HollyFrontier Holdings LLC and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.5 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).
10.2010.14
Refined Products Purchase Agreement, dated December 1, 2009, between Holly Refining & Marketing - Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).
10.21
First Amendment to Refined Products Purchase Agreement, dated May 17, 2010, between Holly Refining & Marketing - Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).
10.22
Second Amendment to Refined Products Purchase Agreement, dated December 19, 2011, between HollyFrontier Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No 1-03876).
10.23
Third Amendment to Refined Products Purchase Agreement, dated June 1, 2012, between HollyFrontier Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.7 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).
10.24
Fourth Amendment to Refined Products Purchase Agreement, dated February 27, 2014, between HollyFrontier Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.55 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 1-03876).
10.25
Fifth Amendment to Refined Products Purchase Agreement dated June 23, 2014, between HollyFrontier Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.56 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 1-03876).
10.26
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 10.26 of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, File No. 1-03876).
118
Table of Content
Exhibit NumberDescription
10.27
10.15
ThirdSeventh Amended and Restated Master Throughput Agreement, dated January 18, 2017, entered into as of February8, 2021, effective as of January 1, 2017, 2021, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.27of10.1 of Registrant's AnnualCurrent Report on Form 10-K for the fiscal year ended December 31, 2016,8-K filed February 11, 2021, File No. 1-03876).
10.2810.16
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 filed October 21, 2015, File No. 1-03876).
10.2910.17
ThirdFourth Amended and Restated Services and Secondment Agreement, dated October 3, 2016, entered into as of 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 to Registrant's Current Report on Form 8-K filed October 4, 2016,February 11, 2021, File No. 1-03876).

Table of Content

Exhibit Number10.18Description
10.30
FourthSixth Amended and Restated Master Lease and Access Agreement, dated January 18, 2017,as of February 8, 2021, effective as of January 1, 2017,2021, by and among certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier Corporation (incorporated by reference to Exhibit 10.3010.6 of Registrant's AnnualCurrent Report on Form 10-K for the fiscal year ended December 31, 2016,8-K filed February 11, 2021, File No. 1-03876).
10.3110.19
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. 1-03876).
10.32
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 filed November 3, 2015, File No. 1-03876).
10.3310.20
Amendment to Master Tolling Agreement (Refinery Assets), dated effective January 1, 2017, by and among HollyFrontier El Dorado Refining LLC, HollyFrontier Woods Cross Refining LLC, and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.7 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017, File No. 1-03876).
10.3410.21
Amended and Restated Master Tolling Agreement (Operating Assets), dated 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 to Registrant's Current Report on Form 8-K filed October 4, 2016, File No. 1-03876).
10.22
10.35
Amendment to Amended and Restated Master Tolling Agreement (Operating Assets), dated effective January 1, 2017, by and among HollyFrontier El Dorado Refining LLC, HollyFrontier Woods Cross Refining LLC, and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.6 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017, File No. 1-03876).
10.3610.23
LLC Interest PurchaseSecond Amendment to Amended and Restated Master Tolling Agreement (Operating Assets), dated February 22, 2016,effective 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 10.67 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2015, File No. 1-03876).
10.37
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 10.68 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2015, File No. 1-03876).
10.38
Second 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 10.310.7 of Registrant's Current Report on Form 8-K filed February 22, 2016,November 1, 2018, File No. 1-03876)1-03846).
10.3910.24
Pipeline Deficiency Agreement, dated August 8, 2016, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 to Registrant's Current Report on Form 8-K filed August 10, 2016, File No. 1-03876).
10.4010.25
LLC Interest PurchaseConstruction Payment Agreement, dated 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 10.1 to10.3 of Registrant's Current Report on Form 8-K filed October 4, 2016,November 1, 2018, File No. 1-03876).
10.41+10.26
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. 1-03876).
10.27
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. 1-03876).

119
Table of Content
Exhibit NumberDescription
10.28+
HollyFrontier Corporation Long-Term Incentive Compensation Plan (formerly the Holly Corporation Long-Term Incentive Compensation Plan), as amended and restated on May 24, 2007 as approved at the Annual Meeting of Stockholders of Holly Corporation on May 24, 2007 (incorporated by reference to Exhibit 10.4 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).
10.42+10.29+
First Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).
10.43+10.30+
Second Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed May 18, 2011, File No. 1-03876).

Table of Content

Exhibit NumberDescription
10.31+
10.44+
Third Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.6 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
10.45+10.32+
Fourth Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed May 15, 2015, File No. 1-03876).
10.46+10.33+
Fifth Amendment to the HollyFrontier Corporation Long-Term Incentive Plan, effective May 11, 2016 (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed May 16, 2016, File No. 1-03876).
10.47+10.34+
HollyFrontier Corporation 2020 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K for filed May 15, 2020, File No. 1-03876).
10.35+
HollyFrontier Corporation Long-Term Incentive Plan UK Sub-Plan, effective February 14, 2017 (incorporated by reference to Exhibit 10.43 of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, File No. 1-03876).
10.48+10.36+
HollyHollyFrontier Corporation Amended and Restated Change in Control Agreement Policy2020 Long-Term Incentive Plan Sub-Plan for UK Employees (incorporated by reference to Exhibit 10.14.4 of Registrant's Current ReportRegistration Statement on Form 8-KS-8 filed MarchJune 1, 2011,2020, File No. 1-03876)333-238835).
10.49+10.37+
HollyHollyFrontier Corporation Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.46 of Registrant's Annual Report on Form 10-K for theits fiscal year ended December 31, 2016, File No. 1-03876).
10.50+10.38+
Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.54 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2018, File No. 1-03876).
10.39+
Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.42 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2019, File No. 1-03876).
10.40+
Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, File No. 1-03876).
10.41+*
Form of Performance Share Unit Agreement.
10.42+*
Form of Restricted Stock Unit Agreement (for 162(m) coverednon-employee directors).
10.43+*
Form of Notice of Grant of Restricted Stock Units (for non-employee directors).
10.44+
Form of Restricted Stock Unit Agreement (for employees) (incorporated by reference to Exhibit 4.1110.61 of the Registrant's Registration StatementAnnual Report on Form S-8 filed November 9, 2012,10-K for its fiscal year ended December 31, 2018. File No. 333-184877)1-03876).
10.51+10.45+
Form of Performance Share Unit AgreementNotice of Grant of Restricted Stock Units (for non-162(m) covered employees) (incorporated by reference to Exhibit 4.1210.62 of the Registrant's Registration StatementAnnual Report on Form S-8 filed November 9, 2012,10-K for its fiscal year ended December 31, 2018. File No. 333-184877)1-03876).
10.52+*10.46+
Form of Performance Share Unit Agreement (for 162(m) covered employees).
10.53+*
Form of Performance Share Unit Agreement (for non-162(m) covered employees).
10.54+
Form of Restricted Stock Unit Agreement (time-based vesting)(for employees) (incorporated by reference to Exhibit 10.49 of Registrant's Annual Report on Form 10-K for theits fiscal year ended December 31, 2016,2019. File No. 1-03876).
120
Table of Content
Exhibit NumberDescription
10.47+
Form of Restricted Stock Unit Agreement (for employees) (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, File No. 1-03876).
10.55+10.48+
Form of Notice of Grant of Restricted Stock Units (for employees) (incorporated by reference to Exhibit 10.50 of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, File No. 1-03876).
10.56+
Form of Restricted Stock Unit Agreement (for non-employee directors) (incorporated by reference to Exhibit 10.63 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012,2019, File No. 1-03876).
10.57+10.49+*
Form of Notice of Grant of Restricted Stock Units (for non-employee directors) (incorporated by reference to Exhibit 10.64 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-03876).
10.58+*
Form of Restricted Stock Unit Agreement (for employees).
10.59+10.50+*
Form of Notice of Grant of Restricted Stock Units (for employees).
10.60+10.51+
Form of Indemnification Agreement entered into with directors and officers of Holly Corporation (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed December 13, 2006, File No. 1-03876).
10.61+
HollyFrontier Corporation Omnibus Incentive Compensation Plan (formerly the Frontier Oil Corporation Omnibus Incentive Compensation Plan) (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).
10.62+
First Amendment to the HollyFrontier Corporation Omnibus Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed May 15, 2015, File No. 1-03876).
10.63+
Second Amendment to the HollyFrontier Corporation Omnibus Incentive Compensation Plan, dated November 9, 2016 (incorporated by reference to Exhibit 10.56 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2016, File No. 1-03876).
10.64+
HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan (formerly the Frontier 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. 1-03876).

Table of Content

Exhibit Number10.52+Description
10.65+
Form of HollyFrontier Corporation Indemnification Agreement between Frontier and each of itsto be entered into with officers and directors of HollyFrontier Corporation and its subsidiaries (incorporated by reference to Exhibit 10.41 to Frontier Oil Corporation's Annual10.2 of registrant's Quarterly Report on Form 10-K10-Q for its fiscal yearthe quarterly period ended December 31, 2006,June 30, 2019, File No. 1-07627)no. 1-03876).
10.66+10.53+
Form of IndemnificationAmended and Restated Consulting Agreement and Release, dated June 30, 2020, by and between HollyFrontier Corporation, HollyFrontier Payroll Services, Inc. and each of its officers and directors (incorporated by reference to Exhibit 10.79 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876).
10.67+
Retirement Agreement, dated January 13, 2017, between HollyFrontier Corporation and Douglas S. AronJames Stump (incorporated by reference to Exhibit 10.1 of Registrant's CurrentRegistrant’s Quarterly Report on Form 8-K filed January 13, 2017,10-Q for the quarterly period ended June 30, 2020, File No. 1-03876).
21.1*
Subsidiaries of Registrant
23.1*
Consent of Independent of 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**
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 Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2017,2020, 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 Statements of Equity, and (vi) Notes to the 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.
121
Table of Content



SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


HOLLYFRONTIER CORPORATION
(Registrant)
Date: February 24, 2021HOLLYFRONTIER CORPORATION/s/ Michael C. Jennings
(Registrant)Michael C. Jennings
Date: February 21, 2018/s/ George J. Damiris
George J. Damiris
Chief Executive Officer and President




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 as of the date indicated.


SignatureCapacityDate
/s/ Michael C. JenningsChief Executive Officer, PresidentFebruary 24, 2021
Michael C. Jenningsand Director
SignatureCapacityDate
/s/ George J. DamirisChief Executive Officer, PresidentFebruary 21, 2018
George J. Damirisand Director
/s/ Richard L. Voliva IIIExecutive Vice President andFebruary 21, 201824, 2021
Richard L. Voliva IIIChief Financial Officer
(Principal Financial Officer)
/s/ J.W. Gann, Jr.Indira AgarwalVice President, Controller andFebruary 21, 201824, 2021
J.W. Gann, Jr.Indira AgarwalChief Accounting Officer
(Principal Accounting Officer)
/s/ Michael C. JenningsFranklin MyersChairman of the BoardFebruary 21, 201824, 2021
Michael C. JenningsFranklin Myers
/s/ Anne-Marie N. AinsworthDirectorFebruary 21, 201824, 2021
Anne-Marie N. Ainsworth
/s/ Douglas Y. BechDirectorFebruary 21, 201824, 2021
Douglas Y. Bech
/s/ Anna C. CatalanoDirectorFebruary 21, 201824, 2021
Anna C. Catalano
/s/ Leldon EcholsDirectorFebruary 21, 201824, 2021
Leldon Echols
/s/ Manuel J. FernandezDirectorFebruary 24, 2021
Manuel J. Fernandez
/s/ R. Kevin HardageCraig KnockeDirectorFebruary 21, 201824, 2021
R. Kevin HardageCraig Knocke
/s/ Robert J. KostelnikDirectorFebruary 21, 201824, 2021
Robert J. Kostelnik
/s/ James H. LeeDirectorFebruary 21, 201824, 2021
James H. Lee
/s/ Franklin MyersDirectorFebruary 21, 2018
Franklin Myers
/s/ Michael E. RoseDirectorFebruary 21, 201824, 2021
Michael E. Rose


106
122