10-K

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, 2017

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)

_________________________________________________________________

Delaware	75-1056913
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2828 N. Harwood, Suite 1300 Dallas, Texas	75201-1507
(Address of principal executive offices)	(Zip Code)

(214) 871-3555

Registrant’s telephone number, including area code

_________________________________________________________________

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

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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  ý    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.       ¨

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,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	ý	Accelerated filer	¨	Non-accelerated filer	¨	Smaller reporting company	¨
Emerging growth company	¨

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

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

On June 30, 2017, 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 per share, held by non-affiliates of the registrant was approximately $4.5 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.)

177,363,228 shares of Common Stock, par value $.01 per share, were outstanding on February 16, 2018.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 9, 2018, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2017, are incorporated by reference in Part III.

TABLE OF CONTENTS

Item	Page
PART I
Forward-Looking Statements	3
Definitions	4
1 and 2. Business and properties	6
1A. Risk Factors	22
1B. Unresolved staff comments	32
3. Legal proceedings	33
4. Mine safety disclosures	33
PART II
5. Market for Registrant's common equity, related stockholder matters and issuer purchases of equity securities	34
6. Selected financial data	35
7. Management's discussion and analysis of financial condition and results of operations	36
7A. Quantitative and qualitative disclosures about market risk	51
Reconciliations to amounts reported under generally accepted accounting principles	51
8. Financial statements and supplementary data	53
9. Changes in and disagreements with accountants on accounting and financial disclosure	98
9A. Controls and procedures	98
9B. Other information	98
PART III
10. Directors, executive officers and corporate governance	98
11. Executive compensation	98
12. Security ownership of certain beneficial owners and management and related stockholder matters	98
13. Certain relationships and related transactions, and director independence	99
14. Principal accounting fees and services	99
PART IV
15. Exhibits, financial statement schedules	99
Index to exhibits	100
Signatures	106

2

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:

• risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum 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;

• the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines;

• effects of governmental and environmental regulations and policies;

• the availability and cost of our financing;

• the effectiveness of our capital investments and marketing strategies;

• our efficiency in carrying out construction projects;

• our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate any existing or future acquired operations;

• the possibility of terrorist attacks and the consequences of any such attacks;

• general economic conditions; and

• other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation the forward-looking statements that are referred to above. 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

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 an 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

“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.

“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

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, 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, 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.”

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., 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 the largest manufacturer 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, 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 and operated PCLI located in Mississauga, Ontario, which produces base oils and other specialized lubricant products;

• owned and operated HollyFrontier Asphalt Company (“HFC Asphalt”), which operates various asphalt terminals in Arizona, New Mexico and Oklahoma; and

• owned a 59% limited partner interest and a non-economic general partner interest in HEP.

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 2017 can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”

6

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 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 regions of the United States. We own and operate five complex refineries having a combined crude oil processing capacity of 457,000 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 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 the fourth quarter of 2017, we revised the following refining segment operating data computations: refinery gross margin; net operating margin; and operating expenses to better align with similar measurements provided by other companies in our industry and to facilitate comparison 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 to products purchased for resale and excess crude oil sales. All prior period data has been retrospectively adjusted to reflect our current presentation.

	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.

7

(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,
	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. Specialty lubricant products are sold in both commercial and specialty markets. 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” 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.

8

The following table sets forth information about our Mid-Continent region operations, including non-GAAP performance measures.

	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.

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 process 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.

9

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 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, truck 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 region primarily to paving contractors and manufacturers of roofing products.

For the year ended December 31, 2017, sales to Shell Oil represented approximately 12% 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.

Products

Set forth below is information regarding refined product sales attributable to our Mid-Continent region:

	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.

10

Southwest Region (Navajo Refinery)

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 following table sets forth information about our Southwest region operations, including non-GAAP performance measures.

	Years Ended December 31,
	2017			2016			2015
Southwest Region (Navajo Refinery)
Crude charge (BPD) (1)	100,040			98,090			100,450
Refinery throughput (BPD) (2)	109,280			107,690			111,840
Sales of produced refined products (BPD) (3)	111,630			111,390			114,790
Refinery utilization (4)	100.0		%	98.1		%	100.5		%
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
Net operating margin	$	7.20		$	4.44		$	11.10
Refinery operating expenses per throughput barrel (8)	$	5.31		$	5.23		$	5.38

	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.

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. 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.

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.

11

El Paso Market

The El Paso market for refined products is currently supplied by a number of area and Gulf Coast 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 for refined products is currently supplied by a number of refiners via pipelines 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 deliver 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 use a common carrier pipeline out of El Paso to serve the Albuquerque market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2026, 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 pipeline as well as terminalling facilities in Moriarty, which is 40 miles east of Albuquerque. This facility permits us to ship light products to 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.

Products

Set forth below is information regarding refined product sales attributable to our Southwest region:

	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	%

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.

12

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.

13

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 Colorado 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, 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 and Tulsa rack forward businesses.

14

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

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 business for the period February 1, 2017 (date of acquisition) through December 31, 2017.

	Years Ended December 31,
Lubricants and Specialty Products	2017		2016		2015
Throughput (BPD)	21,710		—		—
Sales of produced refined products (BPD)	31,480		12,030		11,140
Sales of produced refined products:
Finished products	45	%	50	%	52	%
Base oils	31	%	50	%	48	%
Other	24	%	—	%	—	%
Total	100	%	100	%	100	%

PCLI owns and operates a refinery located in Mississauga, Ontario having lubricant production capacity of 15,600 barrels per stream day and has the flexibility to match unique lubricant product formulations. The primary operating units include a hydrogen plant and hydrotreating, solvent dewaxing, hydrodentrification, catalytic dewaxing and hydrobon/platformer units. The Mississauga plant also includes packaging facilities and has extensive distribution capabilities with marine, truck and rail access.

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 in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Delek's refinery in Big Spring, Texas. 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; 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”).

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:

SLC Pipeline and Frontier Aspen

On October 31, 2017, HEP acquired the remaining 75% interest in SLC Pipeline LLC, the owner of 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 subsidiaries of Plains All American Pipeline, L.P. (“Plains”) for total cash consideration of $250.0 million.

15

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 in the second quarter of 2016, for cash consideration of approximately $278.0 million.

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”) 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 Refinery 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 $55.0 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.

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 through 2036. Under 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 index. As of December 31, 2017, these agreements result in minimum annualized payments to HEP of $324.5 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.

16

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, HEP's assets included:

Pipelines

• approximately 810 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;

• crude receiving assets located at our Cheyenne Refinery;

• 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.

Refined Product Terminals and Refinery Tankage

• three refined product terminals located in Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 600,000 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 400,000 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 500,000 barrels, that are integrated with HEP's refined product pipelines that serve Delek's Big Spring, Texas refinery;

• a refined product loading rack facility at each of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries, heavy product / asphalt loading rack facilities at our Tulsa East facility, Navajo Refinery Lovington facility and Cheyenne Refinery, LPG loading rack facilities at our El Dorado Refinery, Tulsa West facility and Cheyenne Refinery, lube oil loading racks at our Tulsa West facility and crude oil Leased Automatic Custody Transfer units located at our Cheyenne Refinery;

• on-site crude oil tankage at our Tulsa, El Dorado, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity of approximately 1,350,000 barrels;

17

• on-site refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate storage capacity of approximately 8,800,000 barrels;

• eleven crude oil tanks adjacent to our El Dorado Refinery with a capacity of approximately 1,200,000 barrels that primarily serve our El Dorado Refinery;

• Frontier Pipeline's tankage with an aggregate capacity of approximately 72,000 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.

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.

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

We lease approximately 92,000 square feet for our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires in 2023. Functions performed in the 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.

Employees and Labor Relations

As of December 31, 2017, we had 3,522 employees, of which 1,139 are currently covered by collective bargaining agreements having various expiration dates between 2018 and 2020. We consider our employee relations to be good.

Environmental Regulation

We are subject to numerous federal, state, provincial and local laws 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 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. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, the results of our operations and our capital expenditures.

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 refineries 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 the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion, and state implementation of the 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

18

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, we are subject to the EPA’s Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations that impose reductions in the benzene content of our produced gasoline. Our refineries currently purchase benzene credits to meet these requirements. If economically justified or otherwise determined to be beneficial, we could implement additional benzene reduction projects to eliminate 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, the EPA finalized the RFS targets for 2018, which maintained the volume required for conventional (i.e., corn ethanol) renewable fuel, increased the volume required for advanced biofuels, and reduced the volume required for cellulosic biofuel compared to the 2017 RFS requirements. The EPA also maintained the biomass-based diesel volume for 2019 compared to 2018. 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 lawsuits have been filed by refiners attempting to move the point of compliance for the RFS from refiners to importers and blenders of fuels. 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 biodiesel 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 secure 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.

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 cap and trade programs, carbon taxes, vehicle efficiency standards 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 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, the EPA proposed to repeal the Clean Power Plan, and on December 18, 2017, the EPA issued a notice seeking comments on whether to promulgate a replacement rule. If upheld, this rule would not directly affect our operations, but, to the extent it or a similar rule is fully implemented, it could result in increased power costs for our refineries in future years.

19

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. 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.

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.

The CWA also regulates filling or discharges to wetlands and other “Waters of the U.S.” In 2015, the EPA, in conjunction with the U.S. Army Corps of Engineers (the “Corps”), issued a final rule regarding the definition of “Waters of the U.S.,” which expanded the regulatory reach of the existing CWA regulations. 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. If the rule or any replacement rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for discharges resulting from our operations.

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.

20

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.

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 and its 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.

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, we had an accrual of $103.7 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 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. 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. 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. 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 catastrophic 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 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, many of the revised requirements do not become effective until 2021. 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.

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.

21

Item 1A. Risk Factors

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. 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 financial statements and related notes, when deciding to invest in us. 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.

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 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 products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns 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, 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, 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 products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil 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.

22

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 / 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 non-cash decrease to cost of products sold in the amount of $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016, respectively.

A material decrease in the supply of crude oil or other raw materials available to our refineries 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. 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 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, there are a limited number of suppliers and, in some cases, the supplies are specific to the particular geographic region in which a facility is located. 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.

23

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 costs 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, our financial condition, results of operations, or cash flows could be materially and adversely affected.

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 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 of 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 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, 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.

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;

• 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.

24

Currency fluctuations or devaluations may impact our operating results.

Fluctuations or devaluations in foreign currencies relative to the U.S. dollar can impact our revenue and our costs of doing business. Most of our products and services are sold through contracts denominated in U.S. dollars; however, some of 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 increase or decrease our revenue and expenses reported in U.S. dollars and may impact our results of operations. 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 competitiveness and control of our cost structure, which could have a material adverse effect on our business, financial condition and results of operations.

We are exposed to fluctuations in foreign currency exchange rates, particularly with respect to the Canadian dollar, the euro and the Chinese renminbi. We recognize foreign currency transaction gains and losses arising from our operations in the period incurred. As a result, currency fluctuations between the U.S. dollar and the currencies in which we do business have caused and will continue to cause foreign currency transaction and translation gains and losses, which could be material. We cannot predict the effects of exchange rate fluctuations upon 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.

We derive a portion of our revenue 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, 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 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 refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use, transportation and distribution of petroleum and hazardous substances by pipeline, truck, rail 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 Canada that are subject to Canadian national and provincial environmental laws and regulations and similar laws in other foreign countries. Permits or other authorizations are required under these laws for the operation of our refineries, 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. 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 EPA 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. 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, the EPA issued a finale rule providing refiners an additional 18 months to comply with a small subset of the rules related to air emissions resulting from startup, shutdown 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

25

for 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.

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 manufactured, handled, used, released or disposed.

We are and have been the subject of various local, state, provincial, federal 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 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 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 to time, new federal energy policy legislation is enacted by the U.S. Congress or the Federal or Provincial Governments of Canada. For example, in December 2007, the U.S. Congress passed 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. 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 adoption of climate change legislation or regulations could result in increased operating costs and reduced demand for the refined products we produce.

The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gas emissions, or “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. 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, which may result in a reduction in demand for the refined products that we produce.

26

Although the U.S. Congress has previously considered legislation to reduce GHG 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 thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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

Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, maritime disasters (including those involving marine vessels/terminals), fires, explosions, hazardous materials releases, cyber-attacks, 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.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and exclusions from coverage may 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. We are not fully insured against all risks incident to our business and therefore, we self-insure certain risks. If any refinery were to experience an interruption in operations, 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.

27

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, network disruptions and breaches 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 monitor and control pipeline operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. 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.

28

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.

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. 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.

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.

29

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

30

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 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.

Product liability claims and litigation could adversely affect our business 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.

31

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 man 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.

As of December 31, 2017, approximately 33% of our employees were represented by labor unions under collective bargaining agreements with various expiration dates. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage 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 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.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

32

Item 3.Legal Proceedings

Commitment and Contingency Reserves

We periodically establish reserves for 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 reserves 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.

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

Environmental Matters

We are reporting the following proceedings 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 if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. 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”) relating to a Notice of Violation issued in late 2016 for possible violations of air quality standards related to operation of certain refinery units at the Cheyenne Refinery in 2016 and 2017. HFCR and the WDEQ are working towards a settlement of this matter.

El Dorado

The El Dorado Refinery is engaged in discussions with, and has responded to document requests from, the EPA and the U.S. Department of Justice (“DOJ”) regarding potential Clean Air Act violations relating to flaring devices and other equipment at the refinery. Topics of the discussions include (a) three information requests for activities occurring 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 (c) a Notice of Violation issued by the EPA in August 2017. We will continue to work with the EPA and DOJ to resolve these matters.

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”). On December 13, 2017, during a meeting between the parties, ODEQ proposed stipulated penalties related to violations of the two Consent Decrees. The violations relate to Clean Air Act regulated fuel gas and flare operations. HFTR is currently negotiating with the ODEQ and the EPA.

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

Not Applicable.

33

PART II

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, our Board of Directors approved a $1 billion share repurchase program authorizing us to repurchase common stock in the open market or through privately negotiated transactions based on market conditions, securities law limitations and other relevant considerations. The following table includes repurchases made under this program during the fourth quarter of 2017.

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, we had approximately 91,488 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.

34

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,
	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 interest	75,847			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:
Basic	176,174			176,101			188,731			197,243			200,419
Diluted	177,196			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.

35

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.

Overview

We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate refineries having a combined nameplate crude oil processing capacity of 457,000 barrels per day that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Our refineries are located in El Dorado, Kansas (the El Dorado Refinery), Tulsa, Oklahoma (the Tulsa Refineries), which comprise two production facilities, the Tulsa West and East facilities, Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross Refinery).

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor to acquire 100% 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.

PCLI 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 and white oils that are distributed to end customers worldwide through a global sales network with locations in Canada, the United States, Europe and China.

For the year ended December 31, 2017, net income attributable to HollyFrontier stockholders was $805.4 million compared to a net loss of $260.5 million and net income $740.1 million for the years ended December 31, 2016, and 2015, respectively. Overall gross refining margins per barrel sold for 2017 increased 42% over the year ended December 31, 2016, which was due principally to higher crack spreads throughout 2017. Included in our financial results for the current year was a long-lived asset impairment charge, offset by an inventory reserve adjustment.

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 million for the year ended December 31, 2017, which is net of the $57.7 million cost reduction resulting from reinstatement of 2016 RINs as described in Note 8 “Inventories” in the Notes to Consolidated Financial Statements.

OUTLOOK

The profitability of our refining business is largely driven by our operational reliability and crack spreads (the price difference between refined products and inputs such as crude oil), which are driven by the supply and demand 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, we expect to benefit from widening crude differentials on some of our key inputs in the Refining segment: Cushing-based crude oils 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 growth as well as the execution of our organic growth strategy.

36

HEP’s business is largely driven by the operational reliability of our refineries and contractual tariff increases. Based on our volume forecasts, we expect HEP to be able to grow its limited partner distribution approximately 4% with a distribution coverage ratio of roughly 1.0x.

A more detailed discussion of our financial and operating results for the years ended December 31, 2017, 2016 and 2015 is presented in the following sections.

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

37

Other Financial Data

	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.

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. The cost of products and refinery gross and net operating margins do not include the non-cash effects of goodwill and asset impairments 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 the fourth quarter of 2017, we revised the following refining segment operating data computations: refinery gross margin; net operating margin; and operating expenses to better align with similar measurements provided by other companies in our industry and to facilitate comparison 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 to products purchased for resale and excess crude oil sales. All prior period data has been retrospectively adjusted to reflect our current presentation.

38

	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 business for the period February 1, 2017 (date of acquisition) through December 31, 2017.

	Years Ended December 31,
Lubricants and Specialty Products	2017	2016	2015
Throughput (BPD)	21,710	—	—
Barrels sold (BPD)	31,480	12,030	11,140

Our Lubricants and Specialty Products segment includes base oil production activities, by-product sales to third parties and intra-segment base oil sales to rack forward referred to as “rack back.” “Rack forward” includes the purchase of base oils and the blending, packaging, marketing and distribution and sales of finished lubricants and specialty products to third parties. Supplemental financial data attributable to our Lubricants and Specialty Products segment is presented below:

39

	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, 2017 Compared to Year Ended December 31, 2016

Summary

Net income attributable to HollyFrontier stockholders for the year ended December 31, 2017 was $805.4 million ($4.54 per basic and $4.52 per diluted share), a $1,065.8 million increase compared to a net loss attributable to HollyFrontier stockholders of $260.5 million ($1.48 per basic and diluted share) for the year ended December 31, 2016. Net income increased due principally to an increase in refining segment sales volumes and 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. For the year ended December 31, 2017, lower of cost or market inventory reserve adjustments increased pre-tax earnings by $108.7 million compared to $291.9 million for the year ended December 31, 2016. Refinery gross margins for the year ended December 31, 2017 increased to $11.56 per barrel sold from $8.16 for the year ended December 31, 2016. During 2017, our Cheyenne Refinery and Woods Cross Refinery were each granted a one-year small refinery exemption 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 million for the year ended December 31, 2017.

40

Sales and Other Revenues

Sales and other revenues increased 35% from $10,535.7 million for the year ended December 31, 2016 to $14,251.3 million for the year ended December 31, 2017 due to a year-over-year increase in sales prices and higher product sales volumes. Sales and other revenues for the years ended December 31, 2017 and 2016 include $77.2 million and $68.9 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 to our Lubricants and Specialty Products segment for the year ended December 31, 2017.

Cost of Products Sold

Total cost of products sold increased 34% from $8,474.0 million for the year ended December 31, 2016 to $11,359.1 million for the year ended December 31, 2017, due principally to higher crude oil costs and higher sales volumes of products. Additionally, cost of products sold reflects a $108.7 million benefit that is attributable to a decrease in 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, 2017 is based on market conditions and prices at that time. Additionally, we recorded a $30.5 million and $27.3 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.

Gross Refinery Margins

Gross refinery margin per barrel sold increased 42% from $8.16 for the year ended December 31, 2016 to $11.56 for the year ended December 31, 2017. This was due to the effects of an increase in the average per barrel sold sales price, partially offset by increased 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 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.

41

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.

42

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% from $1,060.4 million for the year ended December 31, 2015 to $1,018.8 million for the year ended December 31, 2016 due principally to lower natural gas fuel and maintenance costs compared to 2015. For the years ended December 31, 2016 and 2015, operating expenses include $90.4 million and $102.3 million, respectively, in costs attributable to HEP operations.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased 4% from $120.8 million for the year ended December 31, 2015 to $125.6 million for the year ended December 31, 2016, due principally to pre-acquisition costs of PCLI. For the years ended December 31, 2016 and 2015, general and administrative expenses include $10.1 million and $10.2 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 5% from $346.2 million for the year ended December 31, 2015 to $363.0 million for the year ended December 31, 2016. This increase was due principally to depreciation and amortization attributable to capitalized improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2016 and 2015, depreciation and amortization expenses include $68.8 million and $61.7 million, respectively, in costs attributable to HEP operations.

Goodwill and Asset Impairment

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, that relate to our Cheyenne Refinery. See Note 10 “Goodwill” in the Notes to Consolidated Financial Statements for additional information on the Cheyenne impairment.

Interest Income

Interest income for the year ended December 31, 2016 was $2.5 million compared to $3.4 million for the year ended December 31, 2015. This decrease was due to higher investment levels in marketable debt securities during 2015.

Interest Expense

Interest expense was $72.2 million for the year ended December 31, 2016 compared to $43.5 million for the year ended December 31, 2015. This increase was due to interest attributable to higher debt levels during 2016 relative to 2015. For the years ended December 31, 2016 and 2015, interest expense included $52.6 million and $36.9 million, respectively, in interest costs attributable to HEP operations.

Loss on Early Extinguishment of Debt

In March 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.

In June 2015, we recognized a $1.4 million early extinguishment loss on the redemption of our $150.0 million aggregate principal amount of 6.875% senior notes maturing November 2018.

Income Taxes

For the year ended December 31, 2016, we recorded income tax expense of $19.4 million compared to $406.1 million for the year ended December 31, 2015. This decrease was due principally to a pre-tax loss during the year ended December 31, 2016 compared to pre-tax earnings during the year ended 2015. Our effective tax rates, before consideration of 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 deductible for income tax purposes.

43

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 ended December 31, 2017, we received advances totaling $26.0 million and repaid $26.0 million under the HollyFrontier Credit Agreement. At December 31, 2017, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $2.8 million under the HollyFrontier Credit Agreement.

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, HEP received advances totaling $969.0 million and repaid $510.0 million under the HEP Credit Agreement. At December 31, 2017, HEP was in compliance with all of its covenants, had outstanding borrowings of $1,012.0 million and no outstanding letters of credit under the HEP Credit Agreement.

HEP Senior Notes

In September 2017, HEP issued an additional $100 million in aggregate principal amount of 6.0% HEP senior 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, HEP redeemed its $300 million aggregate principal amount of 6.50% 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.

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

HEP Common Unit Continuous Offering Program

On 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, HEP issued 1,538,452 common units under this program, providing $52.1 million in net 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. In addition, 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.

44

As of December 31, 2017, our cash and cash equivalents totaled $630.8 million. 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% 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.

In May 2015, our Board of Directors approved a $1 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, we had remaining authorization to repurchase up to $178.8 million 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.

Cash and cash equivalents decreased $79.8 million for the year ended December 31, 2017. Net cash used for investing and financing activities of $959.7 million and $72.6 million, respectively, exceeded net cash provided by operating activities of $951.4 million. Working capital decreased by $127.7 million during the year ended December 31, 2017.

Cash Flows – Operating Activities

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Net cash flows provided by operating activities were $951.4 million for the year ended December 31, 2017 compared to $606.9 million for the year ended December 31, 2016, an increase of $344.4 million. Net income for the year ended December 31, 2017 was $881.2 million, an increase of $1,072.2 million compared to net loss of $190.9 million for the year ended December 31, 2016. 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 equity company acquisition, gain or loss on sale of assets, 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 $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 million for the year ended December 31, 2016 compared to $985.9 million 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, turnaround expenditures increased to $125.3 million from $89.4 million for the same period of 2015.

45

Cash Flows – Investing Activities and Planned Capital Expenditures

Year Ended December 31, 2017 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, 2015

Net cash flows used for investing activities were $801.6 million for the year ended December 31, 2016 compared to $381.7 million for the year ended December 31, 2015, an increase of $419.8 million. Cash expenditures for properties, plants and equipment for 2016 decreased to $479.8 million from $676.2 million for the same period in 2015. These include HEP capital expenditures of $107.6 million and $193.1 million for the years ended December 31, 2016 and 2015, respectively. In addition, in 2016, :HEP purchased a 50% interest in Cheyenne Pipeline for $42.6 million, and in 2015, a 50% interest in Frontier Pipeline for $55.0 million. We received proceeds of $0.8 million and $19.3 million from the sale of assets during the years ended December 31, 2016 and 2015, 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
Turnarounds	200.0		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 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.

46

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. The 2018 HEP capital budget is comprised of $8.0 million for maintenance capital expenditures and $40.0 million for expansion capital expenditures. HEP expects the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks, and enhanced blending capabilities at our racks.

Cash Flows – Financing Activities

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Net cash flows used for financing activities were $72.6 million for the year ended December 31, 2017 compared to cash flows provided by financing activities of $838.7 million for the year ended December 31, 2016, an increase of $911.3 million. During the year ended December 31, 2017, we received $26.0 million and repaid $26.0 million under the HollyFrontier Credit Agreement and paid $235.5 million in dividends. Also during this period, HEP received $969.0 million and repaid $510.0 million under the HEP Credit Agreement, received $101.8 million in net proceeds from issuance of HEP 6.0% senior notes, paid $309.8 million upon the redemption of HEP's 6.5% senior notes, received $52.1 million in net proceeds from the issuance of its common units and paid distributions of $110.4 million to noncontrolling interests. In addition, for the years ended December 31, 2017 and 2016, $15.9 million and $4.7 million, respectively, 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 million. 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. 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 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. During the year ended December 31, 2015, we purchased $742.8 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 to noncontrolling interests.

47

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2017 in total and by period due beginning in 2018. 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, the table below does not reflect renewal options on our operating leases that are likely to be exercised.

			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

(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.

48

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, 2017 and 2016, 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 million and $332.5 million, respectively.

At December 31, 2017, our lower of cost or market inventory valuation reserve was $223.8 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.

Goodwill and Long-lived Assets

As of December 31, 2017, our goodwill balance was $2.2 billion, with goodwill assigned to our Refining, Lubricants and Specialty Products and HEP segments of $1.7 billion, $0.2 billion and $0.3 billion, 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 a comparison of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting unit, we measure goodwill impairment as the excess of 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 the reporting unit.

Our long-lived assets principally consist of our refining assets that are organized as refining asset groups and the assets of our Lubricants and Specialty Products business. The refinery asset groups also constitute our individual refinery reporting units that are used for testing and measuring goodwill impairments. 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.

We performed our annual goodwill impairment testing at July 1, 2017 and determined that 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 at 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.

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 and futures contracts to mitigate price exposure with respect to:

• our inventory positions;

• natural gas purchases;

49

• costs of crude oil and related grade differentials;

• prices of refined products; and

• our refining margins.

As of December 31, 2017, we have the following notional contract volumes related to all outstanding derivative contracts used to mitigate commodity price risk:

		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

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,
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, 2017 is presented below:

	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, outstanding borrowings under the HEP Credit Agreement were $1,012.0 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 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.

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.

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.

50

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 is 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,
	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 barrel sold. These two margins do not include the non-cash effects of 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.

51

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,
	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,
	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

52

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, 2017 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, 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. That report appears on page 55.

53

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, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, HollyFrontier Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, 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, 2017 and 2016, 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, and the related notes of the Company and our report dated February 21, 2018 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.

54

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, 2018

55

Index to Consolidated Financial Statements

	Page Reference
Report of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets at December 31, 2017 and 2016	58
Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015	59
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015	60
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	61
Consolidated Statements of Equity for the years ended December 31, 2017, 2016 and 2015	62
Notes to Consolidated Financial Statements	63

56

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, 2017 and 2016, 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, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 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, 2018 expressed an unqualified opinion thereon.

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.

/s/ Ernst & Young LLP

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

Dallas, Texas

February 21, 2018

57

HOLLYFRONTIER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	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 securities	630,757			1,134,727
Accounts receivable: Product and transportation (HEP: $12,803 and $7,846, respectively)	659,530			449,036
Crude oil resales	61,203			30,163
	720,733			479,199
Inventories: Crude oil and refined products	1,409,538			970,361
Materials, supplies and other (HEP: $916 and $1,402, respectively)	220,554			165,315
	1,630,092			1,135,676
Income taxes receivable	44,337			68,371
Prepayments and other (HEP: $1,395 and $1,486, respectively)	36,909			33,036
Total current assets	3,062,828			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 costs	231,319			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 payable	3,159			—
Accrued liabilities (HEP: $33,214 and $37,793, respectively)	198,756			147,842
Total current liabilities	1,422,710			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, 2016	2,560			2,560
Additional capital	4,132,696			4,026,805
Retained earnings	3,346,615			2,776,728
Accumulated other comprehensive income	29,869			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’ equity	5,370,829			4,681,394
Noncontrolling interest	526,111			620,591
Total equity	5,896,940			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, 2017 and 2016. HEP is a variable interest entity.

See accompanying notes.

58

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)

	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.

59

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	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.

60

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	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.

61

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(In thousands)

	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.

62

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 regions of the United States. In addition, we own and operate a lubricant production facility with retail and wholesale marketing of its products through a global sales network with locations in Canada, United States, Europe and China. As of December 31, 2017, 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 and operated Petro-Canada Lubricants Inc. (“PCLI”) located in Mississauga, Ontario which produces base oils and other specialized lubricant products;

• owned and operated HollyFrontier Asphalt Company (“HFC Asphalt”) which operates various asphalt terminals in Arizona, New Mexico and Oklahoma; and

• owned a 59% limited partner interest and a non-economic general partner interest in HEP, a variable interest entity (“VIE”).

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of PCLI. The acquisition closed on February 1, 2017. See Note 2 for additional information.

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.

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.

63

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 because it more appropriately presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated with such assets and liabilities.

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. 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 million at December 31, 2017 and 2016, respectively.

Accounts receivable attributable to crude oil resales generally represent the sell side 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'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 business 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 RINs are stated at the lower of weighted-average cost or net realizable value.

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 13 for additional information.

Properties, plants and 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.

64

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 million and $22.1 million at December 31, 2017 and 2016, 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, 2016 and 2015.

Intangibles, Goodwill and 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 not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our goodwill impairment testing first entails a comparison of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting unit, we measure goodwill impairment as the excess of 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 the reporting unit.

Our long-lived assets principally consist of our refining assets that are organized as refining asset groups and our lubricants and specialty products business. The refinery asset groups also constitute our individual refinery reporting units that are used for testing and measuring goodwill impairments. 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 10 for information regarding goodwill and long-lived asset impairment charges recorded during the years ended December 31, 2017 and 2016.

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: 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 accounting for investments in which we have a noncontrolling interest, yet have significant influence over the entity. Under the equity method of accounting, 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 for using the equity method of accounting. As of December 31, 2017, HEP's underlying equity and recorded investment balances in the joint ventures are $39.3 million and $85.3 million, respectively. The differences are being amortized as adjustments to HEP's pro-rata share of earnings in the joint ventures.

65

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines. 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 in cost of products sold.

Our Petro-Canada Lubricants 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, and for sales to U.S. distributors, revenues are recognized when products are shipped to the distributors, net of allowances for returns that are expected to be repurchased from the distributors. In both cases, repurchased products are subsequently sold directly to end customers.

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 million, $110.6 million and $107.8 million for the years ended December 31, 2017, 2016 and 2015, 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. 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.

Foreign Currency Translation: The functional currency of PCLI and its affiliated non-U.S. Petro-Canada Lubricants entities includes the Canadian dollar, the euro and Chinese renminbi. Balance sheet accounts 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 corporate and other. See Note 20 for additional information on our segments.

66

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 obligation that is subsequently reversed when the inventory is repurchased. For the years ended December 31,2017, 2016 and 2015, we received proceeds of $47.4 million, $57.0 million and $115.4 million and subsequently repaid $49.8 million, $58.0 million and $115.3 million, respectively, under these sell / buy transactions.

New Accounting Pronouncements

Hedge Accounting

In August 2017, Accounting Standard Update (“ASU”) 2017-12, “Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities,” was issued amending hedge accounting recognition and presentation requirements, including elimination of the requirement to separately measure and report hedge ineffectiveness, and eases certain documentation and assessment requirements. This standard has an effective date of January 1, 2019. We do not expect adoption of this standard to have a material impact on our financial condition, results of operations or cash flows.

Post-retirement Benefit Cost

In March 2017, ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost,” was issued amending 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, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017 on a prospective basis with the excess tax expense from stock-based compensation recognized as a discrete item in our provision for income taxes. Excess tax expense for the year ended December 31, 2017 totaled $0.7 million. The new standard also requires that employee taxes paid when an employer withholds shares 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 leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. 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.

67

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 share purchase agreement with Suncor to acquire 100% 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. PCLI is located in Mississauga, Ontario, Canada and is a producer of lubricant products such as base oils, white oils, specialty products 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 network with locations in Canada, the United States, Europe and China.

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 is accounted for as a business combination using the acquisition method of accounting, with the purchase price allocated to the fair value of the acquired PCLI assets and liabilities as of the February 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.

The following summarizes the PCLI value of assets and liabilities acquired on February 1, 2017:

	(in millions)
Cash and cash equivalents	$	21.6
Accounts receivable and other current assets	118.5
Inventories	214.9
Properties, plants and equipment	438.0
Goodwill	194.8
Intangibles, precious metals and other noncurrent assets	124.3
Accounts payable and accrued liabilities	(87.4		)
Deferred income tax liabilities	(105.4		)
Other long-term liabilities	(12.6		)
Net assets acquired	$	906.7

68

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 for the year ended December 31, 2017 included revenues and income before income taxes of $1,125.3 million and $71.8 million, respectively, related to these operations.

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

NOTE 3: 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 in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Delek’s refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), the owner of 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 the Osage Pipeline and the Cheyenne Pipeline.

At December 31, 2017, we owned a 59% 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 two 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 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% of HEP’s total revenues for the year ended December 31, 2017. 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 12 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 Pipeline

On October 31, 2017, HEP acquired the remaining 75% interest in SLC Pipeline LLC, the owner of 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 subsidiaries of Plains All American Pipeline, L.P. (“Plains”) for cash consideration of $250.0 million.

These acquisitions were accounted for as a business combination achieved in stages. HEP’s preexisting equity method investments 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 investments 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 million and the fair value of HEP's preexisting equity method investments 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 in the second quarter of 2016, for cash consideration of approximately $278.0 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 $56.7 million.

69

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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. Cheyenne Pipeline will continue to be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie, 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. Previously in 2009, we sold these tanks to 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 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. 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.

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 through 2036. Under 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, these agreements result in minimum annualized payments to HEP of $324.5 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.

70

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

On 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, HEP issued 1,538,452 common units under this program, providing $52.1 million in net 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 4: 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.

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.

71

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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, derivative instruments consisting of 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 values of the commodity price and interest rate swap contracts are 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, quoted forward commodity prices with respect to our commodity price swaps and the forward London Interbank Offered Rate (“LIBOR”) yield curve with respect to HEP's interest rate swaps. RINs credit obligations are valued based on current market RINs prices. The fair value of the marketable securities is based on values provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input.

72

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Basic earnings per share is calculated as net income (loss) attributable to HollyFrontier stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares from restricted shares and performance share units. 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,
	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 andperformance 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

As of December 31, 2017, we have two principal share-based compensation plans (collectively, the “Long-Term Incentive Compensation Plan”).

73

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

The compensation cost charged against income for these plans was $39.8 million, $22.8 million and $26.9 million for the years ended December 31, 2017, 2016 and 2015, 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 million, $2.7 million and $3.5 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Restricted Stock and Restricted Stock Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees restricted stock unit awards with awards generally vesting over a period of two to three years. We previously granted restricted stock to certain officers and key employees with awards vesting over a period of three years. Certain restricted 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 share units lapse at which time they convert to common shares. 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.

A summary of restricted stock and restricted stock unit activity and changes during the year ended December 31, 2017 is presented below:

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, 2016 and 2015, restricted stock and restricted stock units vested having a grant date fair value of $24.9 million, $18.4 million and $14.2 million, respectively. For the years ended December 31, 2016 and 2015, we granted restricted stock and restricted stock units having a weighted average grant date fair value of $21.66 and $49.92, respectively. As of December 31, 2017, there was $33.9 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 1.6 years.

Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in stock 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 under these awards can range from zero to 200% of target award amounts. As of December 31, 2017, estimated share payouts for outstanding non-vested performance share unit awards averaged approximately 110% of target amounts.

74

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

A summary of performance share unit activity and changes during the year ended December 31, 2017 is presented below:

Performance Share Units	Grants
Outstanding at January 1, 2017 (non-vested)	703,939
Granted	239,964
Vesting and transfer of ownership to recipients	(151,599	)
Forfeited	(99,643	)
Outstanding at December 31, 2017 (non-vested)	692,661

For the year ended December 31, 2017, we issued 138,374 shares of common stock, representing a 91% payout on vested performance share units having a grant date fair value of $6.6 million. For the years ended December 31, 2016 and 2015, we issued common stock upon the vesting of the performance share units having a grant date fair value of $7.4 million and $10.4 million, respectively. As of December 31, 2017, there was $15.6 million of total unrecognized compensation cost related to non-vested performance share units having a grant date fair value of $33.94 per unit. That cost is expected to be recognized over a weighted-average period of 2.1 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:

	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.

75

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

NOTE 8: Inventories

Inventory consists of the following components:

	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) 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, unfinished and finished products and repair and maintenance supplies in connection with our February 1, 2017 acquisition of PCLI. We value these inventories at the lower of FIFO cost or net realizable value.

Inventories which are valued at the lower of LIFO cost or market reflect a valuation reserve of $223.8 million and $332.5 million at December 31, 2017 and 2016, respectively. The December 31, 2016 market reserve of $332.5 million was reversed due to the sale of inventory quantities that gave rise to the 2016 reserve. A new market reserve of $223.8 million was established as of December 31, 2017 based on market conditions and prices at that time. The effect of the change in the lower of cost or market reserve was a decrease to cost of goods sold of $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016, respectively, and an increase of $227.0 million for the year ended December 31, 2015.

At December 31, 2017, 2016 and 2015, the LIFO value of inventory, net of the lower of cost or market reserve, was equal to current costs.

In May 2017, the EPA granted the Cheyenne Refinery a one-year small refinery exemption from the Renewable Fuel Standard (“RFS”) program requirements for the 2016 calendar year. As a result, the Cheyenne 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. In the second quarter of 2017, we increased our inventory of RINs and reduced our cost of products sold by this amount, representing the cost of the RINs that were reinstated as a result of the RFS exemption received by the Cheyenne Refinery.

Additionally, in December 2017, the EPA granted the Woods Cross Refinery a one-year small refinery exemption from the RFS program requirements for the 2016 calendar year. In the fourth quarter of 2017, we increased our inventory of RINs and reduced our cost of products sold in the amount of $27.3 million, representing the cost of the RINs to be reinstated as a result of the RFS exemption received by the Woods Cross Refinery. These RINs were reinstated in January 2018.

76

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

NOTE 9: Properties, Plants and Equipment

The components of properties, plants and equipment are as follows:

	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 million, $8.0 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Depreciation expense was $286.5 million, $247.9 million and $233.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.

NOTE 10: Goodwill and Long-lived Asset Impairment

As of December 31, 2017, our goodwill balance was $2.2 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.

The following is a summary of our goodwill by segment:

	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

77

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

We performed our annual goodwill 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, we incurred long-lived asset impairment charges totaling $23.2 million, including $19.2 million of construction-in-progress consisting primarily of engineering work for a planned expansion of our Woods Cross refinery to add lubricants production capabilities. During the second quarter of 2017, we concluded to no longer pursue this expansion for various reasons including 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, as a result of our impairment testing in the second quarter of 2016, we determined that the carrying value of the long-lived assets of the Cheyenne Refinery had been impaired and recorded long-lived asset impairment charges of $344.8 million that principally related to properties, plant and equipment.

During the second quarter of 2016, we performed interim goodwill impairment and related long-lived asset impairment testing of our El Dorado and Cheyenne Refinery reporting units after identifying a combination of events and circumstances that are indicators

of potential goodwill and long-lived asset impairment. The indicators included lower than typical gross margins during the summer driving season, a decrease in the gross margin outlook and decrease in our market capitalization due to a decline in our common share price. Our testing first assessed the carrying values of our refining long-lived asset groups for recoverability. This entailed a comparison of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting unit, we measure goodwill impairment as the excess of 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 the reporting unit. The estimated fair values of our goodwill reporting units and long-lived asset groups 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, forecasted production levels, 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-kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs). As a result of our impairment testing during the second quarter of 2016, we determined that the carrying value of the Cheyenne Refinery’s goodwill was fully impaired and a goodwill impairment charge of $309.3 million was recorded, representing all of the goodwill allocated to our Cheyenne Refinery. Our interim testing in 2016 did not identify any 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.

NOTE 11: Environmental

We expensed $13.1 million, $6.6 million and $14.7 million for the years ended December 31, 2017, 2016 and 2015, respectively, for environmental remediation obligations. The accrued environmental liability reflected in our consolidated balance sheets was $103.7 million and $96.4 million at December 31, 2017 and 2016, respectively, of which $89.6 million and $82.9 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.

78

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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 ended December 31, 2017, we received advances totaling $26.0 million and repaid $26.0 million under the HollyFrontier Credit Agreement. At December 31, 2017, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $2.8 million under the HollyFrontier Credit Agreement.

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, HEP received advances totaling $969.0 million and repaid $510.0 million under the HEP Credit Agreement. At December 31, 2017, HEP was in compliance with all of its covenants, had outstanding borrowings of $1,012.0 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% and 2.98% at December 31, 2017 and 2016, 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 2016 and November 2016, we issued $250 million and $750 million, respectively, in aggregate principal amount of 5.875% senior notes (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.

In June 2015, we redeemed our $150.0 million aggregate principal amount of 6.875% senior notes maturing November 2018 at a redemption cost of $155.2 million at which time we recognized a $1.4 million early extinguishment loss consisting of a $5.2 million debt redemption premium, net of an unamortized premium of $3.8 million.

HollyFrontier Financing Obligation

In March 2016, we extinguished a financing obligation at a cost of $39.5 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 repaid with proceeds received upon the November 2016 issuance of the HollyFrontier Senior Notes.

79

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% HEP senior notes in a private placement. HEP used the net proceeds to repay indebtedness under the HEP Credit Agreement.

HEP's 6.0% senior notes ($500 million aggregate principal amount maturing August 2024) (the “HEP Senior 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. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and 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,
	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,
	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 4 for additional information on Level 2 inputs.

80

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

Principal maturities of long-term debt are as follows:

Years Ending December 31,	(In thousands)
2018	$	—
2019	—
2020	—
2021	—
2022	1,012,000
Thereafter	1,500,000
Total	$	2,512,000

NOTE 13: 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:

• our inventory positions;

• natural gas purchases;

• costs of crude oil and related grade differentials;

• prices of refined products; and

• our refining margins.

Accounting Hedges

We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas. We also periodically have 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.

81

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 sales under hedge accounting:

	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 and NYMEX futures contracts to lock in prices on forecasted purchases of inventory. In addition, we periodically have swap contracts that serve as economic hedges (derivatives used for risk management, but not designated as accounting hedges) to lock in basis spread differentials on forecasted purchases 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), which were settled on February 1, 2017, in connection with the closing of the PCLI acquisition. These contracts are measured at fair value with offsetting adjustments (gains/losses) recorded directly to income.

82

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:

	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, we have the following notional contract volumes related to our outstanding derivative contracts serving as economic hedges (all maturing in 2018):

Derivative Instrument	Total Outstanding Notional	Unit of Measure
NYMEX futures (WTI) - short	1,175,000	Barrels
Forward gasoline and diesel contracts - long	85,000	Barrels

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:

	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	)

83

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 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

84

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

At December 31, 2017, we had a pre-tax net unrealized loss of $1.3 million classified in accumulated other comprehensive income that relates to all accounting hedges having contractual maturities through 2021. 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.

NOTE 14: Income Taxes

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.

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.

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,
	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

85

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,
	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, 2017 and 2016 are as follows:

	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, 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	)

86

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

We have Oklahoma income tax credits of $9.7 million that can be carried forward indefinitely, and Kansas income tax credits of $16.8 million that can be carried forward for 16 tax years.

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

	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, 2017 and 2016, there were $53.8 million and $22.1 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 to 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 believe it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase within 12 months of the reporting date based on additional filings.

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. 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.

NOTE 15: Stockholders' Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2017, 2016 and 2015 are presented below:

	Years Ended December 31,
	2017		2016		2015
Common shares outstanding at January 1	177,345,266		180,234,388		196,086,090
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 restricted stock with performance feature	350,063		40,294		43,774
Forfeitures of restricted stock	(139,634	)	(16,795	)	(51,332	)
Purchase of treasury stock (1)	(342,073	)	(3,859,403	)	(16,428,574	)
Common shares outstanding at December 31	177,407,622		177,345,266		180,234,388

(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.

87

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

In May 2015, our Board of Directors approved a $1 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, we had remaining authorization to repurchase up to $178.8 million 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, 2016 and 2015, we withheld shares of our common stock from certain employees in the amounts of $15.9 million, $4.7 million and $6.2 million, respectively. These withholdings were made under the terms of restricted stock 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)

The components and allocated tax effects of other comprehensive income are as follows:

	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	)

88

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

The following table presents the income statement line item effects for reclassifications out of accumulated other comprehensive income (“AOCI”):

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,
	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 17: Post-retirement Plans

In connection with our PCLI acquisition, we agreed to establish employee benefit plans including union and non-union pension plans and a post-retirement healthcare plan for PCLI employees that were previously covered under legacy Suncor plans.

89

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 months ended December 31, 2017:

	February 1, 2017 to December 31, 2017
	(In thousands)
Change in plans' benefit obligations
Pension plans' benefit obligation at acquisition	$	52,155
Service cost	3,598
Interest cost	1,979
Actuarial loss	4,503
Benefits paid	(966		)
Foreign currency exchange rate changes	2,313
Pension plans' benefit obligation - end of year	$	63,582
Change in pension plans assets
Fair value of plans assets at acquisition	$	51,870
Actual return on plans assets	6,182
Benefits paid	(966		)
Foreign currency exchange rate changes	2,175
Fair value of plans assets - end of year	$	59,261
Funded status
Under-funded balance	$	(4,321	)
Amounts recognized in consolidated balance sheets
Accrued pension liability	$	(4,321	)
Amounts recognized in accumulated other comprehensive income
Cumulative actuarial loss	$	1,162

The accumulated benefit obligation was $52.8 million at December 31, 2017. The measurement date used for our pension plans was December 31, 2017.

The weighted average assumptions used to determine end of period benefit obligations:

	December 31, 2017
Discount rate	3.40	%
Rate of future compensation increases	3.00	%

Net periodic pension expense consisted of the following components:

	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

90

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

The weighted average assumptions used to determine net periodic pension expense:

	February 1, 2017 to December 31, 2017
Discount rate	3.80	%
Rate of future compensation increases	3.00	%
Expected long-term rate of return on assets	5.75	%

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 million in 2021, $2.1 million in 2022 and $14.9 million in 2023 to 2027.

Post-retirement Healthcare Plans

We have a post-retirement healthcare and other benefits plan that is available to certain of our employees who satisfy certain age and service requirements. This plan is unfunded and provides 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.

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, 2017 and 2016:

	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

91

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.9 million in 2018; $1.6 million in 2019; $1.6 million in 2020; $1.7 million in 2021; $1.7 million in 2022; and $8.2 million in 2023 through 2027.

The weighted average assumptions used to determine end of period benefit obligations:

	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

Net periodic post-retirement credit consisted of the following components:

	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	)

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	)

92

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 million, $0.1 million and $0.1 million for the years ended December 31, 2017, 2016 and 2015, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $2.7 million and $2.7 million at December 31, 2017 and 2016, respectively. As of December 31, 2017, the projected benefit obligation under this plan was $2.7 million. Annual benefit payments of $0.2 million are expected to be paid through 2027, which reflect expected future service.

Defined Contribution Plan

We have a defined contribution “401(k)” plan that covers substantially all U.S. employees. Our contributions are based on an employee's eligible compensation and years of service. We also partially match our employees’ contributions. We expensed $17.6 million, $17.5 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 million for the years ended December 31, 2017, 2016 and 2015, respectively.

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.

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 2019 through 2033.

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 2018 through 2033. At December 31, 2017, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:

	(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 million, $135.1 million and $137.7 million for the years ended December 31, 2017, 2016 and 2015, 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.

93

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 three reportable 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 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 regions of the United States. HFC Asphalt operates various asphalt terminals in Arizona, New Mexico and Oklahoma.

94

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.

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 processing units in the Mid-Continent, Southwest and Rocky Mountain 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. 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.

The accounting policies for our segments are the same as those described in the summary of significant accounting policies (see Note 1).

	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

95

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

	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% 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 revenues for the year ended December 31, 2017. The Canadian market represents our largest concentration of foreign sales and accounted for 4% of our revenues for the year ended December 31, 2017.

96

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

NOTE 22: Quarterly Information (Unaudited)

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter		Year
	(In thousands, except per share data)
Year Ended December 31, 2017
Sales and other revenues	$	3,080,483		$	3,458,864		$	3,719,247	$	3,992,705	$	14,251,299
Operating costs and expenses	$	3,113,207		$	3,337,179		$	3,269,967	$	3,627,053	$	13,347,406
Income (loss) from operations (1,2)	$	(32,724	)	$	121,685		$	449,280	$	365,652	$	903,893
Income (loss) before income taxes	$	(54,571	)	$	106,069		$	446,103	$	371,262	$	868,863
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
Dividends per common share	$	0.33		$	0.33		$	0.33	$	0.33	$	1.32
Average number of shares of common stock outstanding:
Basic	176,210			176,147			176,149		176,265		176,174
Diluted	176,210			176,302			176,530		177,457		177,196
Year Ended December 31, 2016
Sales and other revenues	$	2,018,724		$	2,714,638		$	2,847,270	$	2,955,068	$	10,535,700
Operating costs and expenses	$	1,935,126		$	3,135,180		$	2,722,505	$	2,842,776	$	10,635,587
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	)
Dividends per common share	$	0.33		$	0.33		$	0.33	$	0.33	$	1.32
Average number of shares of common stock outstanding:
Basic	176,737			175,865			175,871		175,936		176,101
Diluted	176,784			175,865			175,993		176,137		176,101

(1) For 2017, income from operations reflects non-cash lower of cost or market inventory valuation charges of $11.8 million and $84.0 million for the first and second quarters, respectively, and a reduction of $111.1 million and $93.4 million for the third and fourth quarters, respectively.

(2) For 2017, income from operations reflects long-lived asset impairment charges of $23.2 million in the second quarter.

(3) For 2016, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $56.1 million and $138.5 million for the first and second quarters, respectively, and increases of $0.3 million for the third quarter and a reduction of $97.7 million for the fourth quarter.

(4) For 2016, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million , respectively, in the second quarter.

97

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, 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.

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 2017 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, 2018 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, 2018 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, 2018 and is incorporated herein by reference.

98

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, 2018 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, 2018 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	57
Consolidated Balance Sheets at December 31, 2017 and 2016	58
Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015	59
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015	60
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	61
Consolidated Statements of Equity for the years ended December 31, 2017, 2016 and 2015	62
Notes to Consolidated Financial Statements	63

(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 filed or furnished, as applicable, as part of this Annual Report on Form 10-K.

99

HOLLYFRONTIER CORPORATION

INDEX TO EXHIBITS

Exhibits are numbered to correspond to the exhibit table

in Item 601 of Regulation S-K

Exhibit Number	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).
2.2	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).
2.3	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).
2.4	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).
2.5	Equity Restructuring Agreement, dated as of October 18, 2017, by and between HEP Logistics Holdings, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed October 19, 2017, 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).
3.2	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).
4.5	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).
10.1	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).
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).

100

Exhibit Number	Description
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).
10.8	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).
10.9	Second Amended and Restated Refined Products 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 10.3 of Registrant's Current Report on Form 8-K filed February 22, 2016, File No. 1-03876).
10.10	Second Amended and Restated Throughput Agreement (Tucson Terminal), dated September 19, 2013, effective June 1, 2013, among HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013, File No. 1-03876).
10.11*	Eighteenth Amended and Restated Omnibus Agreement, dated January 19, 2018, effective December 8, 2017, by and among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries.
10.12	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).
10.13	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).
10.14	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).

101

Exhibit Number	Description
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).
10.20	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).
10.27	Third Amended and Restated Master Throughput Agreement, dated January 18, 2017, effective January 1, 2017, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.27of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, File No. 1-03876).
10.28	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).
10.29	Third Amended and Restated Services and Secondment Agreement, dated October 3, 2016, 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 10.4 to Registrant's Current Report on Form 8-K filed October 4, 2016, File No. 1-03876).

102

Exhibit Number	Description
10.30	Fourth Amended and Restated Master Lease and Access Agreement, dated January 18, 2017, effective January 1, 2017, by and among certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier Corporation (incorporated by reference to Exhibit 10.30 of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, File No. 1-03876).
10.31	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).
10.33	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).
10.34	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).
10.35	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).
10.36	LLC Interest Purchase 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 10.67 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 HEP 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 10.3 of Registrant's Current Report on Form 8-K filed February 22, 2016, File No. 1-03876).
10.39	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).
10.40	LLC Interest Purchase Agreement, dated October 3, 2016, by and between HollyFrontier Corporation, HollyFrontier Woods Cross Refining LLC, Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed October 4, 2016, File No. 1-03876).
10.41+	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+	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+	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).

103

Exhibit Number	Description
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+	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+	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+	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+	Holly Corporation Amended and Restated Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 1, 2011, File No. 1-03876).
10.49+	Holly 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 the fiscal year ended December 31, 2016, File No. 1-03876).
10.50+	Form of Performance Share Unit Agreement (for 162(m) covered employees) (incorporated by reference to Exhibit 4.11 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
10.51+	Form of Performance Share Unit Agreement (for non-162(m) covered employees) (incorporated by reference to Exhibit 4.12 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
10.52+*	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 Agreement (time-based vesting) (incorporated by reference to Exhibit 10.49 of Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, File No. 1-03876).
10.55+	Form of Notice of Grant of Restricted Stock (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, File No. 1-03876).
10.57+	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+*	Form of Notice of Grant of Restricted Stock Units (for employees).
10.60+	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).

104

Exhibit Number	Description
10.65+	Form of Indemnification Agreement between Frontier and each of its officers and directors (incorporated by reference to Exhibit 10.41 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31, 2006, File No. 1-07627).
10.66+	Form of Indemnification Agreement between HollyFrontier Corporation 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. Aron (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed January 13, 2017, 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, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Equity, and (vi) Notes to the Consolidated Financial Statements.

* Filed herewith.

** Furnished herewith.

+ Constitutes management contracts or compensatory plans or arrangements.

++ Filed electronically herewith.

105

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 21, 2018		/s/ George J. Damiris
		George J. Damiris
		Chief Executive Officer

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.

Signature	Capacity	Date
/s/ George J. Damiris	Chief Executive Officer, President	February 21, 2018
George J. Damiris	and Director
/s/ Richard L. Voliva III	Executive Vice President and	February 21, 2018
Richard L. Voliva III	Chief Financial Officer
	(Principal Financial Officer)
/s/ J.W. Gann, Jr.	Vice President, Controller and	February 21, 2018
J.W. Gann, Jr.	Chief Accounting Officer
	(Principal Accounting Officer)
/s/ Michael C. Jennings	Chairman of the Board	February 21, 2018
Michael C. Jennings
/s/ Anne-Marie N. Ainsworth	Director	February 21, 2018
Anne-Marie N. Ainsworth
/s/ Douglas Y. Bech	Director	February 21, 2018
Douglas Y. Bech
/s/ Anna C. Catalano	Director	February 21, 2018
Anna C. Catalano
/s/ Leldon Echols	Director	February 21, 2018
Leldon Echols
/s/ R. Kevin Hardage	Director	February 21, 2018
R. Kevin Hardage
/s/ Robert J. Kostelnik	Director	February 21, 2018
Robert J. Kostelnik
/s/ James H. Lee	Director	February 21, 2018
James H. Lee
/s/ Franklin Myers	Director	February 21, 2018
Franklin Myers
/s/ Michael E. Rose	Director	February 21, 2018
Michael E. Rose

106

EX-10.11

EIGHTEENTH AMENDED AND RESTATED OMNIBUS AGREEMENT

among

HOLLYFRONTIER CORPORATION,

HOLLY ENERGY PARTNERS, L.P.

and

CERTAIN OF THEIR RESPECTIVE SUBSIDIARIES

January 19, 2018

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS AND INTERPRETATIONS    3

1.1DEFINITIONS    3

1.2INTERPRETATION    3

ARTICLE II BUSINESS OPPORTUNITIES    3

2.1RESTRICTED BUSINESSES    3

2.2PERMITTED EXCEPTIONS    3

2.3RIGHT OF OFFER    4

2.4PROCEDURE FOR OFFERING ACQUIRED OR CONSTRUCTED ASSETS TO HEP    5

2.5SCOPE OF PROHIBITION    6

2.6ENFORCEMENT    6

2.7LIMITATION ON ACQUISITIONS OF PERMITTED ASSETS BY HEP GROUP MEMBERS    6

2.8TERMINATION OF ARTICLE II    6

ARTICLE III INDEMNIFICATION    6

3.1CONDITIONS OF INDEMNIFICATION BY THE HFC ENTITIES    6

3.2INDEMNIFICATION BY THE HFC ENTITIES    6

3.3CONDITIONS OF INDEMNIFICATION BY HEP ENTITIES    9

3.4INDEMNIFICATION BY HEP ENTITIES    9

3.5MUTUAL GENERAL INDEMNITY    9

3.6EXCLUSIONS FROM INDEMNITY FOR POST-CLOSING DATE CLAIMS    10

3.7INDEMNIFICATION PROCEDURES    10

3.8LIMITATION ON INDEMNIFICATION OBLIGATIONS    12

3.9WAIVER OF SUBROGATION    12

ARTICLE IV GENERAL AND ADMINISTRATIVE EXPENSES    13

4.1GENERAL    13

ARTICLE V RIGHT OF FIRST REFUSAL    14

5.1HFC RIGHT OF FIRST REFUSAL: PROHIBITION ON FURTHER TRANSFER OF TRANSFERRED ASSETS    14

5.2PROCEDURES    14

ARTICLE VI HFC PURCHASE OPTION    17

6.1OPTION TO PURCHASE TULSA TRANSFERRED ASSETS    17

ARTICLE VII API INSPECTIONS    17

7.1API INSPECTIONS    17

ARTICLE VIII DISPUTE RESOLUTION    18

8.1DISPUTE RESOLUTION    18

8.2ARBITRATION    18

8.3CONFLICT    19

ARTICLE IX FORCE MAJEURE    19

9.1FORCE MAJEURE    19

ARTICLE X MISCELLANEOUS    20

10.1CHOICE OF LAW    20

10.2NOTICES    20

10.3ENTIRE AGREEMENT    21

10.4AMENDMENT OR MODIFICATION    21

10.5ASSIGNMENT    21

10.6COUNTERPARTS    21

10.7SEVERABILITY    21

10.8FURTHER ASSURANCES    21

10.9RIGHTS OF LIMITED PARTNERS    21

10.10HEADINGS    22

10.11LIMITATION OF DAMAGES    22

10.12NATURE OF THE RELATIONSHIP    22

EXHIBITS

Exhibit A - Omnibus Agreement Amendments

Exhibit B - Definitions

Exhibit C - Interpretation

Exhibit D - Asset Indemnification Summary

Exhibit E - Administrative Fee

EIGHTEENTH AMENDED AND RESTATED

OMNIBUS AGREEMENT

THIS EIGHTEENTH AMENDED AND RESTATED OMNIBUS AGREEMENT (this “Agreement”) is being entered into on January 19, 2018 and effective as of December 8, 2017 (the “Effective Date”), by and among the following entities (all Delaware limited liability companies unless otherwise noted):

HollyFrontier Corporation, a Delaware corporation (“HFC”), and its Affiliates listed below (singularly, “HFC Entity”; and with HFC collectively, the “HFC Entities”):
	El Paso Operating LLC (“El Paso Operating”)
	HollyFrontier El Dorado Refining LLC (“HollyFrontier El Dorado”)
	HollyFrontier Cheyenne Refining LLC (“HollyFrontier Cheyenne”)
	HollyFrontier Tulsa Refining LLC (“HollyFrontier Tulsa”)
	HollyFrontier Woods Cross Refining LLC (“HollyFrontier Woods Cross”)
	Navajo Pipeline Co., L.P., a Delaware limited partnership (“Navajo Pipeline”)
	HollyFrontier Navajo Refining LLC (“HollyFrontier Navajo”)
	HollyFrontier Refining & Marketing LLC (“HFRM”)
	HollyFrontier Transportation LLC (“HollyFrontier Transportation”)
AND
Holly Energy Partners, L.P., a Delaware limited partnership (“HEP”), and its Affiliates listed below (singularly, “HEP Entity”; and with HEP collectively, the “HEP Entities”):
	Cheyenne Logistics LLC (“Cheyenne Logistics”)
	El Dorado Logistics LLC (“El Dorado Logistics”)
	El Dorado Operating LLC (“El Dorado Operating”)
	El Dorado Osage LLC (“El Dorado Osage”)
	Frontier Aspen LLC
	HEP El Dorado LLC (“HEP El Dorado”)
	HEP Logistics GP, L.L.C. (the “OLP GP”)
	HEP Logistics Holdings, L.P., a Delaware limited partnership (the “General Partner”)
	HEP Mountain Home, L.L.C.
	HEP Navajo Southern, L.P., a Delaware limited partnership
	HEP Pipeline Assets, Limited Partnership, a Delaware limited partnership
	HEP Pipeline GP, L.L.C.
	HEP Pipeline, L.L.C. (“HEP Pipeline”)
	HEP Refining Assets, L.P., a Delaware limited partnership (“HEP Refining Assets”)
	HEP Refining GP, L.L.C.
	HEP Refining, L.L.C. (“HEP Refining”)
	HEP Tulsa LLC (“HEP Tulsa”)
	HEP UNEV Holdings LLC (“HEP UNEV”)
	HEP UNEV Pipeline LLC (“HEP UNEV Pipeline”)
	HEP Woods Cross, L.L.C.
	Holly Energy Partners – Operating, L.P., a Delaware limited partnership (the “Operating Partnership”)
	Holly Energy Storage – Lovington LLC
	Holly Logistic Services, L.L.C. (“Holly GP”),
	Lovington-Artesia, L.L.C.
	NWNAL LLC
	Roadrunner Pipeline, L.L.C. (“Roadrunner”)
	SLC Pipeline LLC
	Woods Cross Operating LLC (“Woods Cross Operating”)

This Agreement amends and restates in its entirety the Seventeenth Amended and Restated Omnibus Agreement which was effective as of January 1, 2017, among certain of the HFC Entities and certain of the HEP Entities which were signatories thereto (the “Previous Amended and Restated Omnibus Agreement”).

RECITALS:

WHEREAS, the Parties entered into an Omnibus Agreement on July 13, 2004 (as amended, the “Original Omnibus Agreement”) to evidence their agreement with respect to various administrative, indemnity and other obligations, which agreement has been further amended and restated as set forth on Exhibit A, resulting in the Previous Amended and Restated Omnibus Agreement.

WHEREAS, the Parties desire to amend and restate the Previous Amended and Restated Omnibus Agreement as provided herein in order to, among other things, consolidate terms from various other agreements between the parties and to clarify terms as more particularly set forth herein.

AGREEMENT:

NOW, THEREFORE, in consideration of the premises and the covenants, conditions and agreements set forth herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

Article IDEFINITIONS AND INTERPRETATIONS

1.1Definitions.Capitalized terms used throughout this Agreement and not otherwise defined herein shall have the meanings set forth on Exhibit B.

1.2Interpretation. Matters relating to the interpretation of this Agreement are set forth on Exhibit C.

ARTICLE IIBUSINESS OPPORTUNITIES

2.1Restricted Businesses. For so long as a HFC Group Member owns a controlling interest in the general partner of HEP, and except as permitted by Section 2.2, Holly GP and each HFC Group Member shall be prohibited from engaging in or acquiring a controlling interest in or operating any business having assets or operations engaged in the Restricted Businesses.

2.2Permitted Exceptions. Notwithstanding any provision of Section 2.1 to the contrary, Holly GP and the HFC Group Members may engage in the following activities under the following circumstances:

(a) the ownership and/or operation of any of the Retained Assets (including replacements of the Retained Assets);

(b) any Restricted Businesses conducted by a HFC Group Member and Holly GP with the approval of the General Partner;

(c) the ownership and/or operation of Restricted Businesses by an HFC Entity or Holly GP in its capacity as general partner of HEP or its general partner;

(d) the ownership and/or operation of any asset or group of related assets used in the Restricted Business that are acquired or constructed by a HFC Group Member or Holly GP after the Closing Date (the “Permitted Assets”), the fair market value of which (as determined in good faith by the Board of Directors of HFC) is as follows:

(i) less than $5 million at the time of such acquisition or good faith estimate of construction costs, as the case may be; or

(ii) equal to or greater than $5 million at the time of the acquisition or good faith estimate of construction costs; provided, HEP has been offered the opportunity to purchase the Permitted Assets in accordance with Section 2.3 and HEP has elected not to purchase the Permitted Assets;

(e) the ownership of the UNEV Profits Interest;

(f) the ownership of limited or any general partnership interests in HEP; and

(g) the ownership and/or operation of the El Paso Hawkins Terminal.

2.3Right of Offer.

(a) If Holly GP or a HFC Group Member becomes aware of an opportunity to acquire Permitted Assets with a fair market value (as determined in good faith by the Board of Directors of HFC) equal to or greater than $5 million, then, subject to Section 2.3(c), as soon as practicable, Holly GP or such HFC Group Member shall notify HEP of such opportunity and deliver to HEP, or provide HEP access to all information prepared by or on behalf of, or material information submitted or delivered to, Holly GP or such HFC Group Member relating to such potential transaction. As soon as practicable, but in any event within 30 days after receipt of such notification and information, HEP shall notify Holly GP or the HFC Group Member that it has either elected:

(i) not to cause a HEP Group Member to pursue the opportunity to purchase the Permitted Assets, or

(ii) to cause a HEP Group Member to pursue the opportunity to purchase the Permitted Assets, in which case the applicable Parties shall follow the procedures in Section 2.4.

(b) If, at any time, HEP abandons such opportunity (as evidenced in writing by HEP to the HFC Group Member), Holly GP or the HFC Group Member may pursue such opportunity. Any Permitted Assets which are permitted to be acquired by Holly GP or a HFC Group Member must be so acquired:

(i) within 12 months of the later to occur of (i) the date that Holly GP or the HFC Group Member becomes able to pursue such acquisition in accordance with the provisions of this Section 2.3, and (ii) the date upon which all required governmental approvals to consummate such acquisition have been obtained, and

(ii) on terms not materially more favorable to Holly GP or the HFC Group Member than were offered to HEP.

If either of these conditions are not satisfied, the opportunity must be reoffered to HEP in accordance with Section 2.3(a).

(c) Section 2.3(a) shall not apply if Holly GP or a HFC Group Member:

(i) becomes aware of an opportunity to make an acquisition that includes Permitted Assets and assets that are not Permitted Assets, and the Permitted Assets have a fair market value (as determined in good faith by the Board of Directors of HFC) equal to or greater than $5 million but comprise less than half of the fair market value (as determined in good faith by the Board of Directors of HFC) of the total assets being considered for acquisition, or

(ii) desires to construct Permitted Assets with an estimated construction cost (as determined in good faith by the Board of Directors of HFC) equal to or greater than $5 million;

provided, however, that in each case Holly GP or a HFC Group Member, as the case may be, shall comply with Section 2.4.

2.4Procedure for Offering Acquired or Constructed Assets to HEP    .

(a) Within 180 days after the consummation of the acquisition or the completion of construction by Holly GP or a HFC Group Member of the Permitted Assets, as the case may be, Holly GP or the HFC Group Member shall notify HEP in writing of such acquisition or construction and offer HEP the opportunity to purchase such Permitted Assets (the “Offer”). The Offer shall set forth the terms relating to the purchase of the Permitted Assets, and, if Holly GP or any HFC Group Member desires to utilize the Permitted Assets, the Offer will also include (i) the commercially reasonable terms on which the HEP Group will provide services to Holly GP or the HFC Group Member to enable Holly GP or the HFC Group Member to utilize the Permitted Assets and (ii) the terms of any service agreements, leases or access agreements to be provided to HEP by Holly GP or the HFC Group relating to such assets. As soon as practicable, but in any event within 30 days after receipt of such written notification, HEP shall notify Holly GP or the HFC Group Member in writing that HEP has elected (i) not to cause a HEP Group Member to purchase the Permitted Assets, in which event Holly GP or the HFC Group Member shall be forever free to continue to own or operate such Permitted Assets, or (ii) to cause a HEP Group Member to purchase the Permitted Assets, in which event Section 2.4(b) and Section 2.4(c) shall apply.

(b) If within 60 days after receipt by HEP of the Offer, Holly GP or the HFC Group Member and HEP are able to agree on the fair market value of the subject Permitted Assets and the other terms of the Offer including, the terms, if any, on which the HEP Group will provide services to Holly GP or the HFC Group Member to enable it to utilize the Permitted Assets, a HEP Group Member shall purchase the Permitted Assets for the agreed upon fair market value as soon as commercially practicable after such agreement has been reached and, if required by the Offer or otherwise agreed, enter into an agreement with Holly GP or the HFC Group Member to provide services in a manner consistent with the Offer.

(c) If Holly GP or the HFC Group Member and HEP are unable to agree within 60 days after receipt by HEP of the Offer on the fair market value of the subject Permitted Assets and/or the other terms of the Offer, Holly GP or the HFC Entity, on the one hand, and HEP, on the other hand, will engage a mutually agreed upon investment banking firm to determine the disputed terms. Such investment banking firm will determine the disputed terms within 30 days of its engagement and furnish Holly GP or the HFC Group Member, on the one hand, and HEP, on the other hand, its determination. The fees of the investment banking firm will be split equally between Holly GP or the HFC Group Member, on the one hand, and HEP, on the other hand. Once the investment banking firm has submitted its determination of the disputed terms, HEP will have the right, but not the obligation, to cause a HEP Group Member to purchase the Permitted Assets pursuant to the Offer as modified by the determination of the investment banking firm. HEP will provide written notice of its decision to Holly GP or the HFC Group Member within 30 days after the investment banking firm has submitted its determination. Failure to provide such notice within such 30-day period shall be deemed to constitute a decision not to purchase the Permitted Assets. If HEP elects to cause a HEP Group Member to purchase the Permitted Assets, then the HEP Group Member shall purchase the Permitted Assets pursuant to the Offer as modified by the determination of the investment banking firm as soon as commercially practicable after such determination and, if applicable, enter into an agreement with Holly GP or the HFC Group Member to provide services in a manner consistent with the Offer, as modified by the determination of the investment banking firm, if applicable.

2.5Scope of Prohibition. Except as provided in this Article II and the Partnership Agreement, Holly GP and each HFC Group Member shall be free to engage in any business activity, including those that may be in direct competition with any HEP Group Member.

2.6Enforcement. Holly GP and the HFC Group Members agree and acknowledge that the HEP Group does not have an adequate remedy at law for the breach by Holly GP and the HFC Group of the covenants and agreements set forth in this Article II, and that any breach by Holly GP and the HFC Group of the covenants and agreements set forth in this Article II would result in irreparable injury to the HEP Group. Holly GP and the HFC Group Members further agree and acknowledge that any HEP Group Member may, in addition to the other remedies that may be available to the HEP Group, file a suit in equity to enjoin Holly GP and the HFC Group from such breach and hereby consent to the issuance of injunctive relief under this Agreement.

2.7Limitation on Acquisitions of Permitted Assets by HEP Group Members. Notwithstanding anything in this Agreement to the contrary, a HEP Group Member who is not a party to this Agreement is prohibited from acquiring Permitted Assets. In the event HEP desires a HEP Group Member who is not a party to this Agreement to acquire any Permitted Assets, then the General Partner shall first cause such HEP Group Member to become a party to this Agreement.

2.8Termination of Article II. The provisions of this Article II may be terminated by HFC upon a Change of Control of HFC.

ARTICLE IIIINDEMNIFICATION

3.1Conditions of Indemnification by the HFC Entities    . All indemnities set forth in Section 3.2 are subject to the following conditions:

(a) Except for the indemnity in Sections 3.2(a)(ii), (vii) and (viii), indemnities apply only to the Transferred Assets and only until the applicable expiration date, if any, related to each such Transferred Asset shown on Exhibit D.

(b) The aggregate liability of the HFC Entities for all Covered Environmental Losses under Section 3.2(a) shall not exceed the amounts shown in column (b) on Exhibit D. The liability limits listed in column (b) represent separate individual limits for each location.

(c) Indemnities in Section 3.2(a)(i) apply only to the extent that such events or conditions occurred before the applicable Closing Date.

3.2Indemnification by the HFC Entities.

(a) Subject to Section 3.1, the HFC Entities shall indemnify, defend and hold harmless the HEP Entities from and against any Liability or Claim incurred by the HEP Entities or any Third Party to the extent arising out of:

(i) the Covered Environmental Losses relating to the Transferred Assets to the extent caused by the acts or omissions of an HFC Entity;

(ii) the ownership or operation by HFC and its Affiliates of any asset not constituting part of the Transferred Assets, except to the extent arising out of the negligent acts or omissions or willful misconduct of HEP or any of its Affiliates;

(iii) the failure of the applicable HEP Entity to be the owner of valid and indefeasible easement rights or fee ownership for interests in and to the lands on which any pipeline or related pump station, tank farm or equipment conveyed or contributed or otherwise Transferred (including by way of a Transfer of the ownership interest of a Person or by operation of law) to the applicable HEP Entity on the applicable Closing Date;

(iv) the failure of the applicable HEP Entity to have the consents, licenses and permits necessary to allow any such Transferred Assets referred to in Section 3.2(a)(iii) to cross the roads, waterways, railroads and other areas upon which any such Transferred Assets are located as of the Closing Date;

(v) the cost of curing any condition set forth in clauses (iii) or (iv) above to the extent such conditions do not allow any Transferred Asset to be operated in accordance with Prudent Industry Practice;

(vi) the following:

(A) events and conditions associated with the operation of the Transferred Assets before the Closing Date (other than Covered Environmental Losses which are provided for under Section 3.2(a)(i) and events and conditions covered by Section 3.4);

(B) all legal actions pending against the HFC Entities on July 13, 2004;

(C) the completion of remediation projects at the respective HEP Entity’s El Paso Hawkins Terminal, Albuquerque terminal and Mountain Home terminal that were ongoing or scheduled as of July 13, 2004;

(D) events and conditions associated with the Retained Assets and whether occurring before or after the Closing Date;

(E) all federal, state and local tax liabilities attributable to the operation or ownership of the Transferred Assets prior to the applicable Closing Date, including any such tax liabilities of the HFC Entities that may result from the consummation of the formation transactions for the HEP Entities and the General Partner; and

(F) any breach by HollyFrontier Tulsa of the representations and warranties set forth in Section 3.9 of the Master Lease and Access Agreement.

(vii) the operation by HEP and its Affiliates of any assets owned by HFC or any of its Affiliates, except to the extent arising out of the gross negligence or willful misconduct of HEP or any of its Affiliates;

(viii) any failure to perform any covenant or agreement made or undertaken by HFC or its Affiliates in the (A) Master Lease and Access Agreement, or the exercise by HFC or its Affiliates of any rights and obligations under Section 2.2 thereof; or (B) Services and Secondment Agreement; except in either case to the extent arising out of the willful misconduct or negligence (standard negligence or gross negligence) of HEP or any of its Affiliates; and

(ix) any failure of HEP or any of its Affiliates to perform its obligations pursuant to the Storage and Handling Agreement to the extent arising after February 22, 2016, except to the extent arising out of gross negligence and willful misconduct of HEP or any of its Affiliates.

(b) The indemnities provided for in Section 3.2(a)(i) through (v) shall only apply if the HFC Entities are notified in writing of any of the foregoing prior to the applicable expiration date listed in column (b) on Exhibit D.

(c) The indemnities provided for in Section 3.2(a)(vi) shall only apply if to the extent that the HFC Entities are notified in writing of any of the following events and conditions within five years after the applicable Closing Date.

(d) Notwithstanding anything in this Agreement to the contrary, because HEP has been involved since the inception with the following Transferred Assets, as used in this Section 3.2, the definition of “Transferred Assets” shall not include the 16” Lovington/Artesia Intermediate Pipeline, the Beeson Pipeline, the Roadrunner Pipeline, the Tulsa Interconnecting Pipelines, and the UNEV Pipeline.

(e) To the extent that a good faith Claim by the HEP Entities for indemnification under Section 3.2(a) arises from events or conditions at the Transferred Tanks or the soil immediately underneath the Transferred Tanks or the Transferred Tanks’ secondary containment, and the HFC Entities refuse to provide such indemnification, then the burden of proof shall be on the HFC Entities to demonstrate that the events or conditions giving rise to the Claim arose after the Closing Date.

(f) As used in this Section 3.2, “Affiliates” of the Indemnifying Party shall not include the HEP Group Members when a HFC Entity is the Indemnifying Party and shall not include the HFC Group Members when the Indemnifying Party is a HEP Entity.

3.3Conditions of Indemnification by the HEP Entities    .The indemnities set forth in Section 3.4 apply only to the extent that such events or conditions occurred on or after the applicable Closing Date, if any.

3.4Indemnification by the HEP Entities.

(a) Subject to Section 3.3, the HEP Entities shall indemnify, defend and hold harmless the HFC Entities from and against any Liability or Claim suffered or incurred by the HFC Entities or any Third Party to the extent arising from:

(i) the Covered Environmental Losses associated with operation of (A) the Other Assets (except as otherwise indicated in Exhibit D, Part 2), and (B) the Transferred Assets by a Person (other than a HFC Entity or ownership and operation of the Transferred Assets by a Person other than a HFC Entity);

(ii) operation by HEP and HEP’s Affiliates of any asset owned by HFC or any of HFC’s Affiliates but only to the extent caused by the gross negligence or willful misconduct of any of the HEP Entities; and

(iii) any failure to perform any covenant or agreement made or undertaken by any HEP or its Affiliates in the (A) Master Lease and Access Agreement, or the exercise by HEP or its Affiliates of any rights and obligations under Section 2.2 thereof; or (B) Services and Secondment Agreement; except in either case to the extent arising out of the willful misconduct or negligence (standard negligence or gross negligence) of HFC or any of its Affiliates.

(b) Nothing set forth in Section 3.4(a) shall make the HEP Entities responsible for any post-Closing Date negligent actions or omissions or willful misconduct by the HFC Entities.

(c) Notwithstanding Section 3.4(a)(i), the indemnity provided for in Section 3.4(a)(i) shall only apply to the El Dorado Repurchased Tanks to the extent the Environmental Losses arise from a violation, correction, event or condition occurring during the period that El Dorado Logistics owned such Repurchased Tanks.

3.5Mutual General Indemnity. Following the applicable Closing Dates, the HFC Entities and the HEP Entities, respectively, agree to indemnify, protect, defend and hold harmless each other from and against any and all Liabilities and Claims based upon, in connection with, relating to or arising out of their respective actions or inactions in connection with the operation of the Indemnifying Party’s respective assets or any failure to comply with any Applicable Laws; in any case of or by any Indemnifying Party or its subcontractors, suppliers, materialmen, employees, agents, successors and assigns, or other persons directly or indirectly employed by them, including the following:

(a) any injury to or death of any Person or the damage to or theft, destruction, loss or loss of use of, any property; or

(b) the failure to perform any covenant or agreement made or undertaken by the applicable Party in agreements with any of the other Parties.

3.6Exclusions from Indemnity for Post-Closing Date Claims.NOTWITHSTANDING ANYTHING HEREIN TO THE CONTRARY, FOR ANY LIABILITIES OR CLAIMS ARISING OUT OF EVENTS OCCURRING AFTER AN APPLICABLE CLOSING DATE:

(a) EXCEPT AS EXPRESSLY PROVIDED IN SECTION 3.2(a)(vii), THE INDEMNIFICATION OBLIGATIONS HEREIN SHALL NOT EXTEND TO THE PROPORTIONATE AMOUNT OF ANY SUCH LIABILITY OR CLAIM CAUSED BY THE NEGLIGENCE OR WILLFUL MISCONDUCT OF AN INDEMNITEE OR ITS AGENTS OR EMPLOYEES.

(b) No statute, rule or regulation that precludes an injured party from bringing an action against a fellow employee or employer shall preclude a Party from seeking and obtaining a judicial determination of the fault or negligence of such Persons.

(c) Each Party shall be responsible for any insurance deductibles or self-insured retention arising out of any Liability or Claim to the extent such Liability or Claim arises out of the negligence or willful misconduct of such Party, except to the extent the subrogation waiver provided for in Section 3.9 applies to such Liability or Claim.

3.7Indemnification Procedures.

(a) The Indemnified Party agrees that promptly after it becomes aware of facts giving rise to a Claim for indemnification under this Article III, it will provide notice thereof in writing to the Indemnifying Party, specifying the nature of and specific basis for such Claim.

(b) The Indemnifying Party shall have the right to control all aspects of the defense of (and any counterclaims with respect to) any claims brought against the Indemnified Party that are covered by the indemnification under this Article III, including, the selection of counsel, determination of whether to appeal any decision of any court and the settling of any such matter or any issues relating thereto; provided, however, that no such settlement shall be entered into without the consent of the Indemnified Party unless it includes a full release of the Indemnified Party from such matter or issues, as the case may be.

(c) The Indemnified Party agrees to cooperate fully with the Indemnifying Party, with respect to all aspects of the defense of any Claims covered by the indemnification under this Article III, including, the prompt furnishing to the Indemnifying Party of any correspondence or other notice relating thereto that the Indemnified Party may receive, permitting the name of the Indemnified Party to be utilized in connection with such defense, the making available to the Indemnifying Party of any files, records or other information of the Indemnified Party that the Indemnifying Party considers relevant to such defense and making available to the Indemnifying Party any employees of the Indemnified Party.

(d) In no event shall the obligation of the Indemnified Party to cooperate with the Indemnifying Party as set forth in Section 3.7(c) be construed as imposing upon the Indemnified Party an obligation to hire and pay for counsel in connection with the defense of any Claims covered by the indemnification set forth in this Article III; provided, however, that the Indemnified Party may, at its own option, cost and expense, hire and pay for counsel in connection with any such defense. The Indemnifying Party agrees to keep any such counsel hired by the Indemnified Party informed as to the status of any such defense, but the Indemnifying Party shall have the right to retain sole control over such defense.

(e) In connection with the indemnities in this Article III, Indemnifying Party:

(i) agrees to use reasonable efforts to minimize the impact thereof on the operations of the Indemnified Party;

(ii) agrees to enter into a joint defense agreement with Indemnifying Party in order to allow communication by counsel if Indemnified Party elects to involve separate counsel; and

(iii) agrees to maintain the confidentiality of all files, records, and other information furnished by the Indemnified Party pursuant to this Section 3.7.

(f) The amounts for which an Indemnified Party is entitled to indemnification under this Article III shall be reduced by the net amounts recovered by the Indemnified Party pursuant to contractual indemnities from any Third Party (other than pursuant to insurance policies that are not required to include a waiver of subrogation pursuant to Section 3.9) after deducting the reasonable unreimbursed out-of-pocket fees and expenses incurred by the Indemnified Party in recovering such amounts (the “Net Recovery”).  If the Indemnified Party receives a Net Recovery subsequent to an indemnification payment by the Indemnifying Party under this Article III, then such Indemnified Party shall promptly reimburse the Indemnifying Party for any payment made or expense incurred by such Indemnifying Party in connection with providing such indemnification payment up to Net Recovery.  An Indemnified Party shall be obligated to pursue all contractual indemnities (including insurance claims) that such Indemnified Party has with any Third Party, provided, however, if the Indemnified Party’s right to such indemnification is assignable, the Indemnified Party may, in its sole discretion and in lieu of pursuing such claim, elect to assign such indemnification claim to the Indemnifying Party to pursue and shall reasonably cooperate with the Indemnifying Party (including, making its relevant books, records, officers, information and testimony reasonably available to the Indemnifying Party) in the Indemnifying Party’s pursuit of such claim.

(g) For avoidance of doubt, no Claim may be asserted pursuant to Section 3.2 or Section 3.4 following the applicable expiration of the indemnity related to such Claim; provided that any Claim asserted in writing prior to the expiration date of such indemnity that is the basis for such Claim shall survive until such Claim is finally resolved and satisfied. The date on which notification of a Claim for indemnification is received by the Indemnifying Party shall determine whether such Claim is timely made.

3.8Limitation on Indemnification Obligations.

(a) Notwithstanding anything in this Agreement to the contrary, when referring to the indemnification obligations of the HFC Entities in Article III, the definition of HFC Entities shall be deemed to mean solely (b) the HFC Entity or HFC Entities that own or operate, or owned or operated immediately prior to the transfer to the HEP Entities, the Retained Asset, Transferred Asset or other property in question with respect to which indemnification is sought by reason of such HFC Entity’s or HFC Entities’ ownership or operation of the Retained Asset, Transferred Asset or other property in question or that is responsible for causing such loss, damage, injury, judgment, claim, cost, expense or other liability suffered or incurred by the HEP Entities for which it is entitled to indemnification under Article III and (c) HFC.

(b) Notwithstanding anything in this Agreement to the contrary, when referring to the indemnification obligations of the HEP Entities in Article III, the definition of HEP Entities shall be deemed to mean solely (d) the HEP Entity or HEP Entities that own or operate, or previously owned or operated, the Transferred Asset or other property in question or that is responsible for causing such loss, damage, injury, judgment, claim, cost, expense or other liability suffered or incurred by the HFC Entities for which they are entitled to indemnification under Article III, (e) HEP and (f) Operating Partnership.

(c) For the avoidance of doubt, any indemnification obligations of the HFC Entities in Article III with respect to any indemnifiable losses incurred by or attributable to the UNEV Pipeline shall be (i) limited to an amount that is the product of (x) the amount of such losses, multiplied by (y) HEP UNEV’s direct or indirect percentage ownership interest in the UNEV Pipeline at the time such losses were incurred and (ii) payable to, for the benefit of and recoverable solely by HEP UNEV or any HEP Entity designated by HEP UNEV (and not by UNEV Pipeline, LLC).

3.9Subrogation; Waiver of Subrogation. To the extent that any of the HFC Entities or HEP Entities in fact receive full indemnification payments pursuant to Section 3.2(a)(viii) or Section 3.4(a)(iii) hereof, as the case may be, the HFC Entity or HEP Entity paying such Claim shall be subrogated to the receiving party’s rights with respect to the transaction or event requiring or giving rise to such indemnity. Notwithstanding the foregoing, each of the HFC Entities and the HEP Entities, hereby waives and releases, and shall cause their respective insurers, to waive and release, all rights against each other and any of their respective contractors, subsidiaries, consultants, agents and employees for loss or damages to any of the Transferred Assets to the extent of fire and other hazards covered by property insurance applicable to the property to which such loss or damage occurs, except such rights as they have to proceeds of such insurance. For the purposes of this Section 3.9, all deductibles shall be considered insured losses. Without limiting the foregoing, all of the Parties’ policies of property insurance for the Transferred Assets shall be endorsed to provide a complete waiver for the benefit of the other Parties and their Affiliates of (i) any right of recovery which the insurer may have or acquire against the other Parties or any of its Affiliates, or its or their employees, officers or directors for payments made or to be made under such policies and (ii) any lien or right of subrogation which the insurer may have or acquire for payments made or to be made to any person or entity who asserts a Claim against such other Parties or any of its Affiliates, or its or their employees, officers or directors. The releases and waivers of subrogation set forth above in this paragraph shall apply notwithstanding any obligation of a Party to indemnify the other Party for the Claim(s) at issue.

ARTICLE IVGENERAL AND ADMINISTRATIVE EXPENSES

4.1General.

(a) The Operating Partnership will pay HFC an administrative fee (the “Administrative Fee”), payable in equal quarterly installments, for the provision by HFC and its Affiliates for the HEP Group’s benefit of all the general and administrative services that HFC and its Affiliates provide, including, the general and administrative services listed on Exhibit E. As of December 31, 2017, the Administrative Fee is $2,464,000.

(b) The Administrative Fee shall be adjusted on July 1, 2018, effective as of January 1, 2018, by an amount equal to the PPI Adjustment. Thereafter, the Administrative Fee shall be adjusted on July 1 of each calendar year, commencing on July 1, 2019, by an amount equal to the PPI Adjustment. If the PPI is no longer published, then HFC and HEP shall negotiate in good faith to agree on a new index that gives comparable protection against inflation, and the same method of adjustment for increases in the new index shall be used to calculate increases in the Administrative Fee. If the Parties are unable to agree, a new index will be determined by the dispute resolution process in Article VIII.

(c) At the end of each year, either Party will have the right to submit to the other Party a proposal to change the Administrative Fee for that year and/or the method of adjusting the Administrative Fee if either Party believes in good faith that the general and administrative services performed by HFC and its Affiliates for the benefit of the HEP Group for the year in question are inconsistent with the Administrative Fee for that year. If either Party submits such a proposal, the Parties agree that they will negotiate in good faith to determine if the Administrative Fee for that year should be changed and, if so, the amount of such change. If the Parties are unable to agree, the Parties will submit the matter to dispute resolution pursuant to Article VIII.

(d) The Administrative Fee shall not include and the HEP Group shall reimburse HFC and its Affiliates for:

(i) salaries of employees of HFC or its Affiliates, to the extent, but only to the extent, such employees perform services for the HEP Group;

(ii) the cost of employee benefits relating to employees of HFC or its Affiliates, such as 401(k), pension, and health insurance benefits, to the extent, but only to the extent, such employees perform services for the HEP Group and have not been paid by HEP pursuant to the Master Site Services Agreement and the Services and Secondment Agreement;

(iii) any amounts payable under the Master Site Services Agreement and the Services and Secondment Agreement;

(iv) all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided by the HFC and its Affiliates to HEP pursuant to Section 4.1(a); and

(v) all premiums for insurance policies carried for and on behalf of HEP.

(e) Either HFC, on the one hand, or HEP, on the other hand, may terminate this Article IV, by providing the other with written notice of its election to do so at least six months prior to the proposed date of termination.

ARTICLE VRIGHT OF FIRST REFUSAL

5.1HFC Right of First Refusal: Prohibition on Transfer.

(a) The HEP Entities hereby grant to HFC a right of first refusal on any proposed Transfer (other than a grant of a security interest to a bona fide third-party lender or a Transfer to another HEP Group Member) of any of the Assets.

(b) The HEP Entities are prohibited from Transferring any of the Assets to a HEP Group Member that is not a party to this Agreement. In the event the HEP Entities desire to Transfer any of the Assets to a HEP Group Member that is not a Party to this Agreement, they shall first cause the proposed transferee HEP Group Member to become a Party to this Agreement.

(c) The Parties acknowledge that all potential Transfers of Sale Assets pursuant to this Article V are subject to obtaining any and all required written consents of governmental authorities and other third parties and to the terms of all existing agreements in respect of the Sale Assets.

(d) Notwithstanding anything in this Agreement to the contrary, as used in Article V the definition of “Assets” shall not include the Tulsa Transferred Assets or the UNEV Pipeline, but shall expressly include the equity interests of UNEV Pipeline, LLC, HEP UNEV Pipeline, HEP UNEV, El Dorado Osage and Osage then owned directly or indirectly by the HEP Entities.

5.2Procedures.

(a) If a HEP Entity proposes to Transfer any of the Assets to any Person pursuant to a bona fide third-party offer (an “Acquisition Proposal”), then HEP shall promptly give written notice (a “Disposition Notice”) thereof to HFC. The Disposition Notice shall set forth the following information in respect of the proposed Transfer:

(i) the name and address of the prospective acquiror (the “Proposed Transferee”);

(ii) the Assets subject to the Acquisition Proposal (the “Sale Assets”);

(iii) the purchase price offered by such Proposed Transferee (the “Offer Price”);

(iv) reasonable detail concerning any non-cash portion of the proposed consideration, if any, to allow HFC to reasonably determine the fair market value of such non-cash consideration;

(v) the HEP Entities’ estimate of the fair market value of any non-cash consideration; and

(vi) all other material terms and conditions of the Acquisition Proposal that are then known to the HEP Entities.

(b) To the extent the Acquisition Proposal consists of consideration other than cash (or in addition to cash) the Offer Price shall be deemed equal to the amount of any such cash plus the fair market value of such non-cash consideration. In the event HFC and the HEP Entities agree as to the fair market value of any non-cash consideration, HFC will provide written notice of its decision regarding the exercise of its right of first refusal to purchase the Sale Assets within 30 days of its receipt of the Disposition Notice (the “First ROFR Acceptance Deadline”). Failure to provide such notice within such 30-day period shall be deemed to constitute a decision not to purchase the Sale Assets.

(c) In the event (i) HFC’s determination of the fair market value of any non-cash consideration described in the Disposition Notice (to be determined by HFC within 30 days of receipt of such Disposition Notice) is less than the fair market value of such consideration as determined by the HEP Entities in the Disposition Notice and (ii) HFC and the HEP Entities are unable to mutually agree upon the fair market value of such non-cash consideration within 30 days after HFC notifies the HEP Entities of its determination thereof, the HEP Entities and HFC shall engage a mutually-agreed-upon investment banking firm to determine the fair market value of the non-cash consideration. Such investment banking firm shall be instructed to return its decision within 30 days after all material information is submitted thereto, which decision shall be final. The fees of the investment banking firm will be split equally between HFC and the HEP Entities. HFC will provide written notice of its decision regarding the exercise of its right of first refusal to purchase the Sale Assets to the HEP Entities within 30 days after the investment banking firm has submitted its determination (the “Second ROFR Acceptance Deadline”). Failure to provide such notice within such 30-day period shall be deemed to constitute a decision by HFC not to purchase the Sale Assets.

(d) If HFC fails to exercise a right during any applicable period set forth in this Section 5.2, HFC shall be deemed to have waived its rights with respect to such proposed disposition of the Sale Assets, but not with respect to any future offer of such Sale Assets.

(e) If HFC chooses to exercise its right of first refusal to purchase the Sale Assets under Sections 5.1(a) and 5.2(c), HFC and the HEP Entities shall enter into a purchase and sale agreement for the Sale Assets which shall include the following terms:

(i) HFC will agree to deliver cash for the Offer Price (or any other consideration agreed to by HFC and the HEP Entities (each in their sole discretion));

(ii) the HEP Entities will represent that they have good, indefeasible and unencumbered title to the Sale Assets, subject to all recorded and unrecorded matters and all physical conditions and other matters in existence on the closing date for the Sale Assets, plus any other reasonable and customary matters and such matters as HFC may approve, which approval will not be unreasonably withheld. If HFC desires to obtain any title insurance with respect to the Sale Assets, the full cost and expense of obtaining the same (including the cost of title examination, document duplication and policy premium) shall be borne by HFC;

(iii) the HEP Entities will grant to HFC the right, exercisable at HFC’s risk and expense, to conduct such surveys, tests and inspections of the Sale Assets as HFC may deem desirable, so long as such surveys, tests or inspections do not damage the Sale Assets or interfere with the activities of the HEP Entities thereon and so long as HFC has furnished the HEP Entities with evidence that adequate liability insurance is in full force and effect;

(iv) HFC will have the right to terminate its obligation to purchase the Sale Assets under this Article V if the results of any searches, surveys, tests or inspections conducted pursuant to Section 5.2(e)(ii) or Section 5.2(e)(iii) above are, in the reasonable opinion of HFC, unsatisfactory;

(v) the closing date for the purchase of the Sale Assets shall, unless otherwise agreed to by HFC and the HEP Entities, occur no later than 90 days following receipt by the HEP Entities of written notice by HFC of its intention to exercise its option to purchase the Sale Assets pursuant to Section 5.2(b) or (c);

(vi) the HEP Entities shall execute, have acknowledged and deliver to HFC a special warranty deed, assignment of easement, or comparable document, as appropriate, in the applicable jurisdiction, on the closing date for the purchase of the Sale Assets constituting real property interests conveying the Sale Assets unto HFC free and clear of all encumbrances created by the HEP Entities other than those set forth in Section 5.2(e)(ii) above;

(vii) the sale of any Sale Assets shall be made on an “as is,” “where is” and “with all faults” basis, and the instruments conveying such Sale Assets shall contain appropriate disclaimers; and

(viii) neither the HEP Entities nor HFC shall have any obligation to sell or buy the Sale Assets if any of the material consents referred to in Section 5.1(c)have not been obtained or such sale or purchase is prohibited by Applicable Law.

(f) HFC and the HEP Entities shall cooperate in good faith in obtaining all necessary governmental and other Third Party approvals, waivers and consents required for the closing. Any such closing shall be delayed, to the extent required, until the third Business Day following the expiration of any required waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; provided, however, that such delay shall not exceed 120 days and, if governmental approvals and waiting periods shall not have been obtained or expired, as the case may be, by such 120th day, then HFC shall be deemed to have waived its right of first refusal with respect to the Sale Assets described in the Disposition Notice and thereafter neither HFC nor HEP shall have any further obligation under this Article V with respect to such Sale Assets unless such Sale Assets again become subject to this Article V pursuant to Section 5.2(g).

(g) If the Transfer to the Proposed Transferee is not consummated in accordance with the terms of the Acquisition Proposal within the later of (i) 180 days after the later of the applicable ROFR Acceptance Deadline, and (ii) 10 days after the satisfaction of all governmental approval or filing requirements, if any, the Acquisition Proposal shall be deemed to lapse, and the HEP Entities may not Transfer any of the Sale Assets described in the Disposition Notice without complying again with the provisions of this Article V if and to the extent then applicable.

ARTICLE VIHFC PURCHASE OPTION

6.1Option to Purchase Tulsa Transferred Assets. The Parties acknowledge the purchase options and right of first refusal granted to an Affiliate of HFC with respect to the Tulsa Transferred Assets in the Purchase Option Agreement.

ARTICLE VII
API INSPECTIONS

7.1API Inspections. With respect only to the 2008 Tanks, the applicable HFC Entity that sold the particular tank(s) to the applicable HEP Entity shall, during the period that commences on the applicable Closing Date and ends five (5) years thereafter (the “Initial Tank Inspection Period”) reimburse the applicable HEP Entity for the actual costs associated with the first regularly scheduled API 653 inspection (the “Initial Tank Inspections”) and the costs associated with the replacement of the tank mixers on each of the Transferred Tanks after the Closing Date and any repairs required to be made to the 2008 Tanks as a result of any discovery made during the Initial Tank Inspections; provided, however, that

(a) such HFC Entity shall not reimburse such HEP Entity with respect to the relocated crude oil Tank 437 in the Artesia refinery complex or the new crude oil tank to replace crude oil Tank 439 in the Artesia refinery complex more particularly described in the Purchase and Sale Agreement referenced in the definition of 2008 Crude Pipelines, Tanks and Related Assets, and

(b) upon expiration of the Initial Tank Inspection Period, all of the obligations of the applicable HFC Entity pursuant to this Article VII shall terminate, except that the Initial Tank Inspection Period shall be extended if, and only to the extent that

(i) inaccessibility of the 2008 Tanks during the Initial Tank Inspection Period caused the delay of an Initial Tank Inspection originally scheduled to be performed during the Initial Tank Inspection Period, and

(ii) the applicable HFC Entity received notice from the applicable HEP Entity regarding such delay at the time it occurred.

ARTICLE VIIIDISPUTE RESOLUTION

8.1Dispute Resolution.

(a) Any Arbitrable Dispute arising out of or in connection with this Agreement, including any question regarding the existence, validity or termination of this Agreement, shall be exclusively resolved in accordance with this Article VIII.

(b) In the event of a Arbitrable Dispute between an HFC Entity and an HEP Entity, the HFC Entity and the HEP Entity shall, within ten (10) days of a written request by either of them to the other, meet in good faith to resolve such Arbitrable Dispute in a meeting that includes individuals with authority to resolve the Arbitrable Dispute at such meeting.

(c) If the HFC Entity and the HEP Entity are unable to resolve the Arbitrable Dispute within ten (10) days after submission of such Arbitrable Dispute as provided in Section 8.1(b), either the HFC Entity or the HEP Entity may submit the matter to arbitration in accordance with the terms of Section 8.2 below.

(d) Pending resolution of any Arbitrable Dispute between the HFC Entity and the HEP Entity, the HFC Entity and the HEP Entity shall continue to perform in good faith their respective obligations under this Agreement based upon the last agreed performance demonstrated prior to the Arbitrable Dispute.

(e) Resolution of any Arbitrable Dispute between the HFC Entity and the HEP Entity involving payment of money by either the HFC Entity and the HEP Entity to the other shall include payment of interest at the Prime Rate from the original due date of such amount.

(f) Each of the HFC Entity and the HEP Entity shall, in addition to all rights provided herein or provided by Law, be entitled to the remedies of specific performance and injunction to enforce its rights hereunder.

8.2Arbitration    . Any and all Arbitrable Disputes must be resolved through the use of binding arbitration using three arbitrators, in accordance with the Commercial Arbitration Rules of the American Arbitration Association, as supplemented to the extent necessary to determine any procedural appeal questions by the Federal Arbitration Act (Title 9 of the United States Code, as amended from time to time).

(a) Arbitration must be initiated within the time limits set forth in this Agreement, or if no such limits apply, then within the time period allowed by the applicable statute of limitations. Arbitration may be initiated by either party (“Claimant”) by delivering written notice to the other (“Respondent”) that the Claimant elects to refer the Arbitrable Dispute to binding arbitration. Claimant’s notice initiating binding arbitration must identify the arbitrator Claimant has appointed. The Respondent shall respond to Claimant within thirty (30) days after receipt of Claimant’s notice, identifying the arbitrator Respondent has appointed. If the Respondent fails for any reason to name an arbitrator within the 30-day period, Claimant shall petition the American Arbitration Association for appointment of an arbitrator for Respondent’s account. The two arbitrators so chosen shall select a third arbitrator within thirty (30) days after the second arbitrator has been appointed.

(b) The hearing will be conducted in Dallas, Texas and commence within thirty (30) days after the selection of the third arbitrator. The parties and the arbitrators shall proceed diligently and in good faith in order that the award may be made as promptly as possible. Except as provided in the Federal Arbitration Act, the decision of the arbitrators will be binding on, and non-appealable by, the Claimant and Respondent.

(c) The Claimant will pay the compensation and expenses of the arbitrator named by it, and the Respondent will pay the compensation and expenses of the arbitrator named by or for it. The Claimant and Respondent will each pay one-half of the compensation and expenses of the third arbitrator.

(d) All arbitrators must (i) be neutral parties who have never been officers, directors or employees of any of the Parties or any of their Affiliates and who have not provided consulting services (directly or indirectly) for at least three (3) years prior to their appointment and (ii) have at least seven (7) years’ experience in the petroleum transportation industry.

(e) The arbitrators shall have no right to grant or award indirect, consequential, punitive or exemplary damages of any kind.

(f) The Arbitrable Disputes may be arbitrated in a common proceeding along with disputes under other agreements between the Claimant and Respondent to the extent that the issues raised in such disputes are related. Without the written consent of the Claimant and Respondent, no unrelated disputes (including those with Affiliates of either Claimant or Respondent) or Third Party disputes may be joined to an arbitration pursuant to this Agreement.

8.3Conflict    . If there is any inconsistency between this Article VIII and the Commercial Arbitration Rules or the Federal Arbitration Act, the terms of this Article VIII will control the rights and obligations of the parties seeking arbitration.

ARTICLE IXFORCE MAJEURE

9.1    Force Majeure. In the event of any Party being rendered unable, wholly or in part, by a Force Majeure event from performing its obligations under any of the Master Agreements, Services and Secondment Agreement or this Agreement for a period of more than thirty (30) consecutive days, then, upon the delivery of notice and full particulars of the Force Majeure event relied on (“Force Majeure Notice”) to the other affected Party(ies), the obligations of the Parties, so far are they are affected by the Force Majeure event, shall be suspended during the continuance of any inability so caused. The cause of the Force Majeure event shall, as far as possible, be remedied with all reasonable dispatch, except that no Party shall be compelled to resolve any strikes, lockouts or other industrial disputes other than as it shall determine to be in its best interests.

ARTICLE XMISCELLANEOUS

10.1Choice of Law. This Agreement shall be subject to and governed by the laws of the State of Delaware, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state.

10.2Notices.

(a) Any notice or other communication given under this Agreement shall be in writing and shall be (1) delivered personally, (2) sent by documented overnight delivery service, (3) sent by email transmission, or (4) sent by first class mail, postage prepaid (certified or registered mail, return receipt requested). Such notice shall be deemed to have been duly given (x) if received, on the date of the delivery, with a receipt for delivery, (y) if refused, on the date of the refused delivery, with a receipt for refusal, or (z) with respect to email transmissions, on the date the recipient confirms receipt. Notices or other communications shall be directed to the following addresses:

Notices to the HFC Entities:

HollyFrontier Corporation
2828 N. Harwood, Suite 1300
Dallas, Texas 75201
Attention: President
Email address: president@hollyfrontier.com

with a copy, which shall not constitute notice, but is required in order to give proper notice, to:

HollyFrontier Corporation
2828 N. Harwood, Suite 1300
Dallas, Texas 75201
Attention: General Counsel
Email address: general.counsel@hollyfrontier.com

Notices to the HEP Entities:

Holly Energy Partners, L.P.
c/o Holly Logistic Services, L.L.C.
2828 N. Harwood, Suite 1300
Dallas, Texas 75201
Attention: President
Email address: president-HEP@hollyenergy.com

with a copy, which shall not constitute notice, but is required in order to give proper notice, to:

Holly Energy Partners, L.P.
c/o Holly Logistic Services, L.L.C.
2828 N. Harwood, Suite 1300
Dallas, Texas 75201
Attention: General Counsel
Email address: general.counsel@hollyenergy.com

(b) Any Party may at any time change its address for service from time to time by giving notice to the other Parties in accordance with this Section 10.2.

10.3Entire Agreement. This Agreement, together with the other agreements and instruments referred to herein, constitutes the entire agreement of the Parties relating to the matters contained herein, superseding as of the Effective Date all prior contracts or agreements (including the Original Omnibus Agreement), whether oral or written, relating to the matters contained herein. For avoidance of doubt the Eleventh Amended and Restated Omnibus Agreement, effective as of January 1, 2015, shall remain in full force and effect with respect to any event, act or omission occurring before January 1, 2015.

10.4Amendment or Modification. No amendment or modification of this Agreement shall be valid unless it is in writing and signed by the parties hereto. No waiver of any provision of this Agreement shall be valid unless it is in writing and signed by the Party against whom the waiver is sought to be enforced. Any of the exhibits to this Agreement may be amended, modified, revised or updated by the Parties hereto if each of HFC (on behalf of the HFC Entities) and HEP (on behalf of the HEP Entities) execute an amended, modified, revised or updated exhibit or schedule, as applicable, and attach it to this Agreement. Such amended, modified, revised or updated exhibits shall be sequentially numbered (e.g. Exhibit A‑1, Exhibit A‑2, etc.), dated and appended as an additional exhibit or schedule to this Agreement and shall replace the prior exhibit or schedule, as applicable, in its entirety, except as specified therein. No failure or delay in exercising any right hereunder, and no course of conduct, shall operate as a waiver of any provision of this Agreement. No single or partial exercise of a right hereunder shall preclude further or complete exercise of that right or any other right hereunder.

10.5Assignment. No Party shall have the right to assign any of its rights or obligations under this Agreement without the consent of the other Parties hereto.

10.6Counterparts. This Agreement may be executed in any number of paper or electronic counterparts with the same effect as if all signatory parties had signed the same document. All such counterparts shall be construed together and shall constitute one and the same agreement.

10.7Severability. If any provision of this Agreement shall be held invalid or unenforceable by a court or regulatory body of competent jurisdiction, the remainder of this Agreement shall remain in full force and effect.

10.8Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each Party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions.

10.9Rights of Limited Partners. The provisions of this Agreement are enforceable solely by the Parties to this Agreement, and no Limited Partner (as defined in the Partnership Agreement) of HEP shall have the right, separate and apart from HEP, to enforce any provision of this Agreement or to compel any Party to this Agreement to comply with the terms of this Agreement. There are no Third Party beneficiaries to this Agreement.

10.10Headings. Headings of the Sections of this Agreement are for convenience of the parties only and shall be given no substantive or interpretative effect whatsoever.

10.11Limitation of Damages. NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED IN ANY OTHER PROVISION OF THIS AGREEMENT AND EXCEPT FOR CLAIMS MADE BY THIRD PARTIES WHICH SHALL NOT BE LIMITED BY THIS SECTION, THE PARTIES AGREE THAT THE RECOVERY BY ANY PARTY, INCLUDING, PURSUANT TO ARTICLE III, OF ANY LIABILITIES, DAMAGES, COSTS OR OTHER EXPENSES (i) AS A RESULT OF ANY BREACH OR NONFULFILLMENT BY A PARTY OF ANY OF ITS COVENANTS, AGREEMENTS OR OTHER OBLIGATIONS UNDER THIS AGREEMENT OR (ii) BY REASON OF OR ARISING OUT OF ANY OF THE EVENTS, CONDITIONS OR OTHER MATTERS LISTED IN SECTIONS 3.2 OR 3.4 WHICH THE PARTIES HAVE AGREED TO INDEMNIFY THE OTHER PARTY AGAINST, SHALL BE LIMITED TO ACTUAL DAMAGES AND SHALL NOT INCLUDE OR APPLY TO, NOR SHALL ANY PARTY BE ENTITLED TO RECOVER, ANY INDIRECT, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES (INCLUDING, ANY DAMAGES ON ACCOUNT OF LOST PROFITS OR OPPORTUNITIES OR BUSINESS INTERRUPTION OR DIMINUTION IN VALUE) SUFFERED OR INCURRED BY ANY PARTY; PROVIDED, HOWEVER, THAT SUCH RESTRICTION AND LIMITATION SHALL NOT APPLY TO A PARTY’S OBLIGATION TO INDEMNIFY THE OTHER PARTY:

(X) AS A RESULT OF A THIRD PARTY CLAIM FOR SUCH INDIRECT, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES,

(Y) FOR CLAIMS THAT ARE COVERED BY INSURANCE AND ANY RELATED DEDUCTIBLES, OR

(Z) FOR INDIRECT, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES (INCLUDING LIABILITIES ON ACCOUNT OF LOST PROFITS OR OPPORTUNITIES OR BUSINESS INTERRUPTION OR DIMINUTION IN VALUE) THAT ARE A RESULT OF SUCH INDEMNIFYING PARTY’S OR ITS AFFILIATES’ GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

As used in this Section 10.11, “Affiliates” of the Indemnifying Party shall not include the HEP Group Members when a HFC Entity is the Indemnifying Party and shall not include the HFC Group Members when the Indemnifying Party is a HEP Entity.

10.12Nature of the Relationship. Notwithstanding the foregoing, nothing in this Agreement and no actions taken by the Parties shall constitute a partnership, joint venture, association or other co-operative entity among the Parties or authorize either Party to represent or contract on behalf of the other Party.

[Remainder of Page Intentionally Left Blank]

IN WITNESS WHEREOF, the Parties have executed this Agreement to be effective as of the Effective Date.

HFC ENTITIES:

HOLLYFRONTIER CORPORATION

HOLLYFRONTIER EL DORADO REFINING LLC

HOLLYFRONTIER CHEYENNE REFINING LLC

HOLLYFRONTIER WOODS CROSS REFINING LLC

HOLLYFRONTIER TULSA REFINING LLC

NAVAJO PIPELINE CO., L.P.

HOLLYFRONTIER NAVAJO REFINING LLC

EL PASO OPERATING LLC

HOLLYFRONTIER TRANSPORTATION LLC

By: /s/ George J. Damiris            
Name:    George J. Damiris

Title: Chief Executive Officer and President

HEP ENTITIES:

HOLLY ENERGY PARTNERS, L.P.

By:    HEP Logistics Holdings, L.P.

Its General Partner

By: Holly Logistic Services, L.L.C.

Its General Partner

By:    /s/ Richard L. Voliva III    

Name:     Richard L. Voliva III

Title:     Executive Vice President and Chief Financial Officer

HEP LOGISTICS HOLDINGS, L.P.

By:    Holly Logistic Services, L.L.C,

Its General Partner

By:    /s/ Richard L. Voliva III    

Name:     Richard L. Voliva III

Title: Executive Vice President and Chief Financial Officer

CHEYENNE LOGISTICS LLC

EL DORADO LOGISTICS LLC

EL DORADO OPERATING LLC

EL DORADO OSAGE LLC

FRONTIER ASPEN LLC

HEP EL DORADO LLC

HEP LOGISTICS GP, L.L.C.

HEP MOUNTAIN HOME, L.L.C.

HEP PIPELINE ASSETS, LIMITED PARTNERSHIP

HEP PIPELINE GP, L.L.C.

HEP PIPELINE, L.L.C.

HEP REFINING ASSETS, L.P.

HEP REFINING GP, L.L.C.

HEP REFINING, L.L.C.

HEP TULSA LLC

HEP UNEV HOLDINGS LLC

HEP UNEV PIPELINE LLC

HEP WOODS CROSS, L.L.C.

HOLLY ENERGY PARTNERS – OPERATING, L.P.

HOLLY ENERGY STORAGE – LOVINGTON LLC

HOLLY LOGISTIC SERVICES, L.L.C.

LOVINGTON-ARTESIA, L.L.C.

NWNAL LLC

ROADRUNNER PIPELINE, L.L.C.

SLC PIPELINE LLC

WOODS CROSS OPERATING LLC

By:    /s/ Richard L. Voliva III    

Name:     Richard L. Voliva III

Title: Executive Vice President and Chief Financial Officer

HEP NAVAJO SOUTHERN, L.P.

By:    HEP Pipeline GP, L.L.C.

Its General Partner

By:    /s/ Richard L. Voliva III    

Name:     Richard L. Voliva III

Title:     Executive Vice President and Chief Financial Officer

Exhibit A

to

Eighteenth Amended and Restated Omnibus Agreement

Omnibus Agreement Amendments

Agreement	Effective Date	Reason for Amendment
Original Omnibus Agreement	July 13, 2004	n/a
First Amended and Restated Omnibus Agreement	June 1, 2009	16” Lovington/Artesia Intermediate Pipeline Purchase Agreement
Second Amended and Restated Omnibus Agreement	August 1, 2009	Tulsa West (Sunoco) Asset Purchase Agreement
Third Amended and Restated Omnibus Agreement	October 19, 2009	(i) Tulsa East (Sinclair) Purchase Agreement (ii) Beeson Pipeline Purchase Agreement, and (iii) Roadrunner Pipeline Purchase Agreement
Fourth Amended and Restated Omnibus Agreement	March 31, 2010	LLC Interest Purchase Agreement for certain Tulsa East Assets
Fifth Amended and Restated Omnibus Agreement	August 31, 2011	Tulsa Throughput Agreement
Sixth Amended and Restated Omnibus Agreement	November 1, 2011	LLC Interest Purchase Agreement for Cheyenne Assets and El Dorado Assets
Seventh Amended and Restated Omnibus Agreement	July 12, 2012	UNEV LLC Interest Purchase Agreement
Eighth Amended and Restated Omnibus Agreement	June 1, 2013	Malaga Throughput Agreement
Ninth Amended and Restated Omnibus Agreement	January 7, 2014	Amended and Restated El Dorado Throughput Agreement for the El Dorado New Tank No. 647
Tenth Amended and Restated Omnibus Agreement	September 26, 2014	Amended and Restated Malaga Throughput Agreement
Eleventh Amended and Restated Omnibus Agreement	January 1, 2015	Unloading and Blending Services Agreement (Artesia) and Third Amended and Restated Crude Pipelines and Tankage Agreement (Beeson to Lovington System Expansion)
Twelfth Amended and Restated Omnibus Agreement	January 1, 2015	Artesia Rail Yard Facility, El Dorado Terminal and Cheyenne New Tank No. 117
Thirteenth Amended and Restated Omnibus Agreement	November 2, 2015	LLC Interest Purchase Agreement for the membership interest of El Dorado Operating
Fourteenth Amended and Restated Omnibus Agreement	February 22, 2016	LLC Interest Purchase Agreement for the Osage Membership Interest
Fifteenth Amended and Restated Omnibus Agreement	March 31, 2016	Tulsa West Crude Tank Assets and Tulsa New Tanks
Sixteenth Amended and Restated Omnibus Agreement	October 1, 2016	LLC Interest Purchase Agreement for the membership interest of Woods Cross Operating
Seventeenth Amended and Restated Omnibus Agreement	January 1, 2017	El Dorado Repurchased Tanks

Exhibit B

to

Eighteenth Amended and Restated Omnibus Agreement

Definitions

“8” and 10” Lovington/Artesia Intermediate Pipelines” means the 8-inch pipeline and the 10-inch pipeline, each running from Lovington, New Mexico to Artesia, New Mexico and owned by HEP Pipeline.

“16” Lovington/Artesia Intermediate Pipeline” means the 16-inch pipeline running from Lovington, New Mexico to Artesia, New Mexico, owned by Lovington-Artesia, L.L.C.

“16” Lovington/Artesia Intermediate Pipeline Purchase Agreement” means that certain LLC Interest Purchase Agreement dated as of June 1, 2009, by and among HFC, Navajo Pipeline and the Operating Partnership, pursuant to which Navajo Pipeline transferred and conveyed to the Operating Partnership, and the Operating Partnership acquired, all of the limited liability company interests of Lovington-Artesia, L.L.C., the entity that owns the 16” Lovington/Artesia Intermediate Pipeline.

“2004 Product Pipelines, Terminal and Related Assets” means the assets transferred under the July 13, 2004 Contribution, Conveyance and Assumption Agreement at the time of HEP’s initial public offering.

“2008 Crude Pipelines, Tanks and Related Assets” means the Drop-Down Assets as defined in the Purchase and Sale Agreement, dated February 25, 2008, by and among HFC, Navajo Pipeline, Woods Cross Refining Company, L.L.C., a Delaware limited liability company, and HollyFrontier Navajo, as the seller parties, and HEP, the Operating Partnership, HEP Woods Cross, L.L.C., a Delaware limited liability company, and HEP Pipeline, as the buyer parties.

“2008 Tanks” means the Transferred Tanks included in the 2008 Crude Pipelines, Tanks and Related Assets.

“Acquisition Proposal” is defined in Section 5.2(a).

“Additional Lovington Assets” means the Transferred Lovington Assets as defined in the March 2010 Drop Down LLC Interest Purchase Agreement.

“Additional Tulsa East Assets” means the Transferred Tulsa East Assets as defined in the March 2010 Drop Down LLC Interest Purchase Agreement.

“Administrative Fee” is defined in Section 4.1(a).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Agreement” is defined in the introduction to this Agreement.

“Applicable Law” means any applicable statute, law, regulation, ordinance, rule, judgment, rule of law, order, decree, permit, approval, concession, grant, franchise, license, agreement, requirement, or other governmental restriction or any similar form of decision of, or any provision or condition of any permit, license or other operating authorization issued under any of the foregoing by, or any determination by any Governmental Authority having or asserting jurisdiction over the matter or matters in question, whether now or hereafter in effect and in each case as amended (including, all of the terms and provisions of the common law of such Governmental Authority), as interpreted and enforced at the time in question.

“Arbitrable Dispute” means any and all disputes, Claims, controversies and other matters in question between any of the HEP Entities, on the one hand, and any of the HFC Entities, on the other hand, arising out of or relating to this Agreement, the Master Agreements, or the Services and Secondment Agreement, or the alleged breach hereof and thereof, or in any way relating to the subject matter of this Agreement, the Master Agreements, or the Services and Secondment Agreement, regardless of whether (a) allegedly extra-contractual in nature, (b) sounding in contract, tort or otherwise, (c) provided for by Applicable Law or otherwise or (d) seeking damages or any other relief, whether at law, in equity or otherwise.

“Artesia Blending Facility” means the two tanks and related equipment for the unloading and blending of ethanol and biodiesel at the refined product truck rack located at the refinery owned by HollyFrontier Navajo in Artesia, New Mexico.

“Artesia Rail Yard Facility” means (a) the railroad track siding consisting of approximately 8,300 track feet of siding (rail storage) and two mainline switches and three industry switches located on certain land leased by HFRM from the Operating Partnership pursuant to that certain Track Lease Agreement effective as of November 1, 2014 by and between HEP Refining and HFRM, pursuant to which HEP Refining agreed to lease to HFRM, and HFRM agreed to lease from HEP Refining, the Artesia Rail Yard Facility, and (b) HEP Refining’s leasehold interest, as tenant, under the BNSF Lease (New Mexico), and (c) HEP Refining’s leasehold interest, as landlord, under that certain Sublease Agreement effective as of November 1, 2014 by and between HEP Refining and HFRM, pursuant to which HEP Refining agreed to sublease to HFRM, and HFRM agreed to sublease from HEP Refining, the BNSF Land (New Mexico).

“Assets” means the Transferred Assets and the Other Assets, collectively.

“Beeson Pipeline” means the 8” crude oil pipeline extending from Beeson station to Lovington, New Mexico, owned by HEP Pipeline.

“Beeson Pipeline Purchase Agreement” means that certain Asset Purchase Agreement dated as of December 1, 2009, by and among HFC, Navajo Pipeline and HEP Pipeline, pursuant to which Navajo Pipeline agreed to transfer and convey to HEP Pipeline, and HEP Pipeline agreed to acquire, the Beeson Pipeline.

“Beeson to Lovington System Expansion” means the following project undertaken by HEP Pipeline: the installation of a larger pump at the Beeson station and the replacement of five miles of existing 8-inch pipeline with 10-inch pipeline beginning at the Beeson station end of the Beeson Pipeline.

“BNSF Land (New Mexico)” means the land located in Eddy County, New Mexico leased to HEP Refining pursuant to the BNSF Lease (New Mexico).

“BNSF Lease (New Mexico)” means that certain Lease of Land Including New Track Construction dated to be effective as of February 14, 2014, pursuant to which HEP Reining agreed to lease from BNSF Railway Company the BNSF Land (New Mexico).

“Business Day” means any day other than Saturday, Sunday or other day upon which commercial banks in Dallas, Texas are authorized by law to close.

“Change of Control” means, with respect to any Person (the “Applicable Person”), any of the following events:

(a)     any sale, lease, exchange, or other transfer (in one transaction or a series of related transactions) of all or substantially all of the Applicable Person’s assets to any other Person unless immediately following such sale, lease, exchange, or other transfer such assets are owned, directly or indirectly, by the Applicable Person;

(b)     the consolidation or merger of the Applicable Person with or into another Person pursuant to a transaction in which the outstanding Voting Securities of the Applicable Person are changed into or exchanged for cash, securities, or other property, other than any such transaction where

(i)     the outstanding Voting Securities of the Applicable Person are changed into or exchanged for Voting Securities of a surviving Person or its parent and

(ii)     the holders of the Voting Securities of the Applicable Person immediately prior to such transaction own, directly or indirectly, not less than a majority of the Voting Securities of the surviving Person or its parent immediately after such transaction; and

(c)     a “person” or “group” (within the meaning of Sections 13(d) or 14(d)(2) of the Securities Exchange Act of 1934, as amended) (in the case of HFC, other than a group consisting of some of all of the current control persons of HFC), being or becoming the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934, as amended) of more than 50% of all of the then outstanding Voting Securities of the Applicable Person, except in a merger or consolidation that would not constitute a Change of Control under clause (b) above.

“Cheyenne Assets” is defined in the November 2011 Frontier Drop Down LLC Interest Purchase Agreement.

“Cheyenne Logistics” is defined in the introduction to this Agreement.

“Cheyenne New Tank” means petroleum storage tank no. 117 located at the Cheyenne Refinery Complex.

“Claim” means any existing or threatened future claim, demand, suit, judgment, settlement, action, investigation, proceeding, governmental action, cause of action, claims, demands, causes of action, suits, judgments, settlements, fines, penalties, costs, and expenses (including court costs and reasonable attorneys’ and experts’ fees) of any kind or character (in each case, whether civil, criminal, investigative or administrative), known or unknown, under any theory, including those based on theories of contract, tort, statutory liability, strict liability, employer liability, premises liability, products liability, breach of warranty or malpractice of any and every kind or character, known or unknown, fixed, contingent or suffered.

“Claimant” is defined in Section 8.2(a).

“Closing Date” means

(a)     for all sections other than Articles III and VII, July 13, 2004, the date of the closing of HEP’s initial public offering, and

(b)     for purposes of Articles III and VII, Closing Date means, with respect to a group of assets, the effective date of the purchase of such assets or the stock, partnership interests or membership interests of the entity that directly or indirectly owns such assets, by a HEP Entity (such Closing Date being shown in Exhibit D, column (a)).

“Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of July 13, 2004, among HFC, Navajo Pipeline, the General Partner, HEP, the OLP GP, the Operating Partnership and certain other parties, together with the additional conveyance documents and instruments contemplated or referenced thereunder.

“control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract, or otherwise.

“Covered Environmental Losses” means Environmental Claims to the extent arising from:

(a) any violation or correction of violation of Environmental Laws associated with the ownership or operation of the Assets,or

(b) any event or condition associated with ownership or operation of the Assets (including, the presence of Hazardous Substances on, under, about or migrating from the Assets or the disposal or release of Hazardous Substances generated by operation of the Assets at any non-Asset locations), including:

(i) the cost and expense of any investigation, assessment, evaluation, monitoring, containment, cleanup, repair, restoration, remediation, or other corrective action required or necessary under Environmental Laws;

(ii) the cost or expense of the preparation and implementation of any closure, remedial, corrective action, or other plans required or necessary under Environmental Laws; and

(iii) the cost and expense for any environmental or Toxic Tort pre-trial, trial, or appellate legal or litigation support work.

“Disposition Notice” is defined in Section 5.2(a).

“Effective Date” is defined in the introduction to this Agreement.

“El Dorado Assets” is defined in the November 2011 Frontier Drop Down LLC Interest Purchase Agreement.

“El Dorado Logistics” is defined in the introduction to this Agreement.

“El Dorado New Tank” means petroleum products storage tanks no. 647 and no. 651 located at the El Dorado Refinery Complex.

“El Dorado Operating” is defined in the introduction to this Agreement.

“El Dorado Osage” is defined in the introduction to this Agreement.

“El Dorado Refinery Assets” means “Assets” as defined in that certain LLC Interest Purchase Agreement dated as of October 30, 2015 and effective as of November 1, 2015 by and among HollyFrontier El Dorado, HFC and the Operating Partnership, pursuant to which HollyFrontier El Dorado agreed sell to the Operating Partnership all of the issued and outstanding limited liability company interests in El Dorado Operating.

“El Dorado Repurchased Tanks” means tank 243 and tank 244 located at the El Dorado Terminal that were repurchased by HollyFrontier El Dorado from El Dorado Logistics effective January 1, 2017.

“El Dorado Terminal” means that certain petroleum products tank farm located in El Dorado Kansas, and more particularly described in that certain Membership Interest Purchase Agreement dated as of March 6, 2015 by and between El Dorado Logistics and Rimrock Midstream, LLC, as such terminal may be modified, expanded or upgraded from time to time.

“El Paso Hawkins Terminal” means the El Paso Hawkins Terminal as defined in that certain Refined Products Terminal Transfer Agreement effective as of February 22, 2016 between HEP Refining Assets and El Paso Operating, pursuant to which El Paso Operating acquired the El Paso Hawkins Terminal.

“El Paso Operating” is defined in the introduction to this Agreement.

“Environmental Claims” means environmental and Toxic Tort Liabilities and Claims of any and every kind or character, known or unknown, fixed or contingent.

“Environmental Costs” means (i) the cost and expense of any investigation, assessment, evaluation, monitoring, containment, cleanup, repair, restoration, remediation, or other corrective action required or necessary under Environmental Laws, (ii) the cost or expense of the preparation and implementation of any closure, remedial, corrective action, or other plans required or necessary under Environmental Laws, and (iii) the cost and expense for any Environmental Claim, including pre-trial, trial, or appellate legal or litigation support work.

“Environmental Laws” means all federal, state and local laws, statutes, rules, regulations, orders and ordinances, now or hereafter in effect, relating to protection of the environment, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, the Superfund Amendments Reauthorization Act, the Resource Conservation and Recovery Act, the Clean Air Act, the Federal Water Pollution Control Act, the Toxic Substances Control Act, the Oil Pollution Act, the Safe Drinking Water Act, the Hazardous Materials Transportation Act, and other environmental conservation and protection laws, each as amended from time to time.

“First ROFR Acceptance Deadline” is defined in Section 5.2(b).

“Force Majeure” means acts of God, strikes, lockouts or other industrial disturbances, acts of the public enemy, wars (whether or not an official declaration is made thereof), terrorist attacks, blockades, insurrections, riots, epidemics, landslides, lightening, earthquakes, fires, hurricanes, storms, floods, washouts, freezeoffs, arrests, the order of any Governmental Authority having jurisdiction while the same is in force and effect, civil disturbances, explosions, breakage, accident to machinery, equipment, storage tanks or lines of pipe, repairs, maintenance, inability to obtain or unavoidable delay in obtaining permits, material or equipment, and any other causes whether of the kind herein enumerated or otherwise not reasonably within the control of the Party claiming suspension and which by the exercise of due diligence such Party is unable to prevent or overcome. Notwithstanding anything in this Agreement to the contrary, inability of a Party to make payments when due, be profitable or to secure funds, arrange bank loans or other financing, obtain credit or have adequate capacity or production (other than for reasons of Force Majeure) shall not be regarded as events of Force Majeure.

“Frontier Aspen Pipeline” means the Frontier Aspen Pipeline as defined in the Frontier Aspen Membership Purchase Agreement.

“Frontier Aspen Membership Purchase Agreement” means that certain Membership Interest Purchase Agreement dated effective August 7, 2017 between Plains Pipeline, L.P. and HEP Casper SLC, LLC.

“General Partner” is defined in the introduction to this Agreement.

“Governmental Authority” means any federal, state, local or foreign government or any provincial, departmental or other political subdivision thereof, or any entity, body or authority exercising executive, legislative, judicial, regulatory, administrative or other governmental functions or any court, department, commission, board, bureau, agency, instrumentality or administrative body of any of the foregoing.

“Hazardous Substance” means (a) any substance that is designated, defined or classified as a hazardous waste, hazardous material, pollutant, contaminant, or toxic or hazardous substance, or that is otherwise regulated under any Environmental Law, including, any hazardous substance as defined under the Comprehensive Environmental Response, Compensation, and Liability Act, and (b) petroleum, crude oil, gasoline, natural gas, fuel oil, motor oil, waste oil, diesel fuel, jet fuel and other refined petroleum hydrocarbons.

“HEP” is defined in the introduction to this Agreement.

“HEP El Dorado” is defined in the introduction to this Agreement.

“HEP Entities” is defined in the introduction to this Agreement.

“HEP Entity” means any of the HEP Entities.

“HEP Group” means the HEP Entities and any Subsidiary of any such Person, all of which are treated as a single consolidated entity for purposes of this Agreement.

“HEP Group Member” means any member of the HEP Group.

“HEP Pipeline” is defined in the introduction to this Agreement.

“HEP Refining” is defined in the introduction to this Agreement.

“HEP Refining Assets” is defined in the introduction to this Agreement.

“HEP Tulsa” is defined in the introduction to this Agreement.

“HEP UNEV” is defined in the introduction to this Agreement.

“HEP UNEV Pipeline” is defined in the introduction to this Agreement.

“HFC” is defined in the introduction to this Agreement.

“HFC Group” means the HFC Entities and any Person controlled, directly or indirectly, by HFC other than the HEP Entities.

“HFC Group Member” means any member of the HFC Group.

“HFRM” is defined in the introduction to this Agreement.

“HollyFrontier Cheyenne” is defined in the introduction to this Agreement.

“HollyFrontier El Dorado” is defined in the introduction to this Agreement.

“HollyFrontier Navajo” is defined in the introduction to this Agreement.

“HollyFrontier Transportation” is defined in the introduction of this Agreement.

“HollyFrontier Tulsa” is defined in the introduction to this Agreement.

“HollyFrontier Woods Cross” is defined in the introduction to this Agreement.

“Holly GP” is defined in the introduction to this Agreement.

“Indemnified Claims” means losses, damages, liabilities, Claims, demands, causes of action, judgments, settlements, fines, penalties, costs, and expenses (including, court costs and reasonable attorney's and expert's fees) of any and every kind or character.

“Indemnified Party” means all or part of either the HEP Entities or the HFC Entities, as the case may be, in their capacity as the parties entitled to indemnification in accordance with Article III.

“Indemnifying Party” means all or part of either the HEP Entities or the HFC Entities, as the case may be, in their capacity as the parties from whom indemnification may be required in accordance with Article III.

“Initial Tank Inspections” is defined in Section 7.1.

“Initial Tank Inspection Period” is defined in Section 7.1

“Liability” means with respect to any Person, any economic losses (including, diminution in value and lost profits suffered by third parties to the extent an Indemnified Party is required to pay for such damages), damages, injuries (including, personal injury and death), liabilities, of any and every kind or character, known or unknown, fixed, contingent or suffered.

“Limited Partner” is defined in the Partnership Agreement.

“Malaga Pipeline System” means the Pipeline System, as such term is defined in the Malaga TSA.

“Malaga TSA” means that certain Amended and Restated Transportation Services Agreement (Malaga) dated as of September 26, 2014 by and between HFRM and Operating Partnership, pursuant to which Operating Partnership provides certain transportation services for HFRM on the Malaga Pipeline System, as such agreement may be amended, modified or replaced from time to time.

“March 2010 Drop Down LLC Interest PurchaseAgreement” means that certain LLC Interest Purchase Agreement dated as of March 31, 2010, by and among HFC, Lea Refining Company, HollyFrontier Tulsa, HEP Refining and HEP Tulsa, pursuant to which HFC, Lea Refining Company and HollyFrontier Tulsa agreed to transfer and convey to HEP Refining and HEP Tulsa the Additional Tulsa East Assets and the Additional Lovington Assets.

“Master Agreements” means the Master Lease and Access Agreement, Master Site Services Agreement, Master Systems Operating Agreement, Master Throughput Agreement and Master Tolling Agreements.

“Master Lease and Access Agreement” means that certain Fourth Amended and Restated Master Lease and Access Agreement dated effective as of January 1, 2017 among certain of the HEP Entities and the Refinery Owners.

“Master Site Services Agreement” means that certain Third Amended and Restated Master Site Services Agreement dated effective as of October 1, 2016, as amended, among certain of the HEP Entities and the Refinery Owners.

“Master Systems Operating Agreement” means that certain Amended and Restated Master Systems Operating Agreement dated as of February 22, 2016 among certain of the HEP Entities and the Refinery Owners.

“Master Throughput Agreement” means that certain Third Amended and Restated Master Throughput Agreement effective as of January 1, 2017 between the Operating Partnership and HFRM.

“Master Tolling Agreements” means that certain Master Tolling Agreement (Refinery Assets) dated effective as of November 1, 2015, as amended dated effective as of January 1, 2017, between HollyFrontier El Dorado and the Operating Partnership, and that certain Amended and Restated Master Tolling Agreement (Operating Assets) dated effective as of October 1, 2016, as amended dated effective as of January 18, 2017, between HollyFrontier El Dorado, HollyFrontier Woods Cross and the Operating Partnership.

“Navajo Pipeline” is defined in the introduction to this Agreement.

“Net Recovery” is defined in Section 3.7(f).

“NWNAL Assets” means those assets described in Section 8(a)(i)(2) of the SLC Pipeline Membership Purchase Agreement.

“North Loco Tanks” means the Facilities as defined in that certain Conveyance, Assignment and Bill of Sale (Tanks 1075, 1076 and 1077) effective as of December 8, 2017 by and between HollyFrontier Transportation and HEP Pipeline.

“November 2011 Frontier Drop Down LLC Interest Purchase Agreement” means that certain LLC Interest Purchase Agreement effective as of November 1, 2011, by and among HFC, HollyFrontier Cheyenne, HollyFrontier El Dorado, the Operating Partnership and HEP, pursuant to which HollyFrontier Cheyenne and HollyFrontier El Dorado agreed sell to the Operating Partnership the entities that own the Cheyenne Assets and the El Dorado Assets.

“Offer” is defined in Section 2.4(a)

“Offer Price” is defined in Section 5.2(a)(iii).

“OLP GP” is defined in the introduction to this Agreement.

“Operating Partnership” is defined in the introduction to this Agreement.

“Original Omnibus Agreement” is defined in the recitals to this Agreement.

“Osage” means Osage Pipe Line Company, LLC, a Delaware limited liability company.

“Osage Membership Interest” means a fifty percent (50%) limited liability company membership interest in Osage.

“Other Assets” means those assets owned by a HEP Entity that serve the Refineries and were not conveyed, contributed, or otherwise transferred, directly or indirectly by the HFC Entities to the HEP Entities, as indicated in column (a) of Exhibit D, Part 2; provided, that for the purposes of Section 3.2, Other Assets shall not include that certain 8” pipeline extending 50 miles from the White City Station that was formerly used as a refined products pipeline and that was conveyed to the HEP Entities as part of the 2004 Product Pipelines, Terminal and Related Assets.

“Partnership Agreement” means the Second Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. dated as of October 31, 2017. No amendment or modification to the Partnership Agreement subsequent to the date of this Agreement shall be given effect for the purposes of this Agreement unless consented to by each of the Parties.

“Party” means any one of the entities listed on the signature page to this Agreement, collectively the “Parties”.

“Permitted Assets” is defined in Section 2.2(d).

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization association, government agency or political subdivision thereof or other entity.

“Post-Closing Covered Environmental Losses” means, to the extent such violation, event or condition occurred after the Closing Date:

(a) any violation or correction of violation of Environmental Laws associated with the operation of the Transferred Assets by a Person other than a HFC Entity or ownership and operation of the Transferred Assets by a Person other than a HFC Entity, or

(b) any event or condition associated with the ownership and/or operation of the Transferred Assets by a Person other than a HFC Entity (including the presence of Hazardous Substances on, under, about or migrating to or from the Transferred Assets or the disposal or release of Hazardous Substances generated by operation of the Transferred Assets) including, the Environmental Costs;

provided, however, that nothing stated above shall make the HEP Entities responsible for any post-Closing Date negligent actions or omissions or willful misconduct by any of the HFC Entities.

“PPI” means the Producers Price Index-Commodities-Finished Goods, (PPI), et al.

“PPI Adjustment” means the upper change in the annual change rounded to four decimal places of the PPI, produced by the U.S. Department of Labor, Bureaus of Labor Statistics. The series ID is WPUFD49207 – located at http://www.bls.gov/data/. The change factor shall be calculated as follows: annual PPI index (most current year) less annual PPI index (most current year minus 1) divided by annual PPI index (most current year minus 1). An example for year 2014 change is: PPI (2013) – PPI (2012)] / PPI (2012) or (197.3 – 193.3) / 193.3 or .021 or 2.1%. If the PPI change is negative in a given year then there will be no change in the Administrative Fee.

“Pre-Closing Covered Environmental Losses” means, to the extent such violation, event or condition occurred before the Closing Date:

(a) any violation or correction of violation of Environmental Laws associated with the ownership or operation of the Transferred Assets by a Person other than a HEP Entity or ownership and operation of the Transferred Assets by a Person other than a HEP Entity,or

(b) any event or condition associated with ownership and/or operation of the Transferred Assets by a Person other than a HEP Entity (including, the presence of Hazardous Substances on, under, about or migrating to or from the Transferred Assets or the disposal or release of Hazardous Substances generated by operation of the Transferred Assets), including, the Environmental Costs.

provided, however, that nothing stated above shall make the HFC Entities responsible for any pre-Closing Date negligent actions omissions or willful misconduct by any of the HEP Entities.

“Previous Amended and Restated Omnibus Agreement” is defined in the introduction to this Agreement.

“Proposed Transferee” is defined in Section 5.2(a)(i).

“Prudent Industry Practice” means such practices, methods, acts, techniques, and standards as are in effect at the time in question that are consistent with (a) the standards generally followed by the United States pipeline and terminalling industries or (b) such higher standards as may be applied or followed by the HFC Entities in the performance of similar tasks or projects, or by the HEP Entities in the performance of similar tasks or projects.

“Purchase Option Agreement” has the meaning set forth in the Asset Purchase Agreement, dated August 1, 2009, between HollyFrontier Tulsa, as the seller, and HEP Tulsa, as the buyer.

“Refinery” or “Refineries” means each of the Refinery Complexes identified in the Master Lease and Access Agreement.

“Refinery Owners” means each of the HFC Entities that own one or more of the Refineries.

“Respondent” is defined in Section 8.2(a).

“Restricted Business” or “Restricted Businesses” means the ownership or operation of crude oil pipelines or terminals, intermediate petroleum product pipelines or terminals, refined petroleum products pipelines, terminals, truck racks or crude oil gathering systems in the continental United States.

“Retained Assets” means the pipelines, terminals and other assets and investments owned by any HFC Group Member on the date of the Contribution Agreement that were not conveyed, contributed or otherwise transferred to the HEP Entities pursuant to the Contribution Agreement or otherwise.

“Roadrunner” is defined in the introduction to this Agreement.

“Roadrunner Pipeline” means 16” crude oil pipeline extending from Slaughter station in Texas to Lovington, New Mexico owned by Roadrunner.

“Roadrunner Pipeline Purchase Agreement” means that certain LLC Interest Purchase Agreement dated as of December 1, 2009 by and among Navajo Pipeline and the Operating Partnership, pursuant to which the Operating Partnership acquired, all of the outstanding limited liability company interests of Roadrunner, the entity that owns the Roadrunner Pipeline.

“ROFR Acceptance Deadline” means the First ROFR Acceptance Deadline or the Second ROFR Acceptance Deadline, as applicable, both as defined in Section 5.2(b) and (c).

“Sale Assets” is defined in Section 5.2(a)(ii).

“Second ROFR Acceptance Deadline” is defined in Section 5.2(c).

“Services and Secondment Agreement” means that certain Third Amended and Restated Services and Secondment Agreement dated effective as of October 1, 2016, by and among Holly GP, the Operating Partnership, Cheyenne Logistics, El Dorado Logistics, El Dorado Operating, HEP Tulsa, Woods Cross Operating, HollyFrontier Payroll Services, Inc., a Delaware corporation, HollyFrontier Cheyenne, HollyFrontier El Dorado, HollyFrontier Tulsa and HollyFrontier Woods Cross.

“Sinclair” means Sinclair Tulsa Refining Company.

“Sinclair Purchase Agreement” means that certain Asset Sale and Purchase Agreement dated as of October 19, 2009, by and among HollyFrontier Tulsa, HEP Tulsa and Sinclair, pursuant to which HEP Tulsa acquired the Sinclair Transferred Assets.

“Sinclair Transferred Assets” means the HEP Tulsa Assets as defined in the Sinclair Purchase Agreement.

“SLC Pipeline” means the SLC Pipeline as defined in the SLC Pipeline Membership Interest Purchase Agreement.

“SLC Pipeline Membership Purchase Agreement” means that certain Membership Interest Purchase Agreement dated effective August 7, 2017, between Rocky Mountain Pipeline System LLC and HEP SLC, LLC.

“Storage and Handling Agreement” means that certain Storage and Handling Agreement dated February 21, 1997, between the Operating Partnership and Alon U.S.A., L.P., as amended effective January 1, 2004, September 1, 2008 and March 1, 2011.

“Third Party” means a Person which is not (a) HEP or an Affiliate of HEP, (b) HFC or an affiliate of HFC, (c) a Person that, after the signing of this Agreement becomes a successor entity of HEP, HFC or any of their respective Affiliates. An employee of HFC or HEP shall not be deemed an Affiliate.

“Toxic Tort” means a Claim or cause of action arising from personal injury or property damage incurred by the plaintiff that is alleged to have been caused by exposure to, or contamination by, Hazardous Substances that have been released into the environment by or as a result of the actions or omissions of the defendant.

“Transfer” including the correlative terms “Transferring” or “Transferred” means any direct or indirect transfer, assignment, sale, gift, pledge, hypothecation or other encumbrance, or any other disposition (whether voluntary, involuntary or by operation of law) of the Assets.

“Transferred Assets” means all of the assets conveyed, contributed, or otherwise transferred, directly or indirectly (including by transfer or sale of the entity that owns such assets or the entity that owns the interests in the entity that owns such assets) that serve the Refineries, by the HFC Entities to the HEP Entities, as indicated in column (a) of Exhibit D, Part 1; provided that for the purposes of Section 3.2, the term “Transferred Assets” shall include (a) that certain 8” pipeline extending 50 miles from the White City Station that was formerly used as a refined products pipeline and that was conveyed to the HEP Entities as part of the 2004 Product Pipelines, Terminal and Related Assets, and (b) the Tulsa West Crude Tank Assets.

“Transferred Tanks” means the tanks included in the Assets, as indicated in column (h) of Exhibit D, provided however that from and after January 1, 2017, such tanks shall not include the El Dorado Repurchased Tanks.

“Tulsa Interconnecting Pipelines” means the Interconnecting Pipelines as defined in the Tulsa Throughput Agreement.

“Tulsa New Tanks” means petroleum products storage tank nos. 45 and 444A located at the Tulsa Refinery Complex.

“Tulsa Purchase Agreement” means that certain Asset Purchase Agreement dated as of August 1, 2009, by and between HollyFrontier Tulsa and HEP Tulsa, pursuant to which HollyFrontier Tulsa transferred and conveyed to HEP Tulsa, and HEP Tulsa acquired, the Tulsa Transferred Assets.

“Tulsa Throughput Agreement” means that certain Second Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated as of August 31, 2011, pursuant to which HEP Tulsa agreed to provide transportation services to HollyFrontier Tulsa with respect to the Tulsa Interconnecting Pipelines.

“Tulsa Transferred Assets” means the Transferred Assets as defined in the Tulsa Purchase Agreement.

“Tulsa West Crude Tank Assets” means the Leased Property as defined in the Bill of Sale, Assignment and Assumption Agreement dated as of March 31, 2016 between Plains Marketing, L.P. and HEP Tulsa.

“UNEV LLC Interest Purchase Agreement” means that certain LLC Interest Purchase Agreement dated as of July 12, 2012, by and among HFC, HEP UNEV and HEP, pursuant to which HFC agreed to sell to HEP UNEV the entity that owns 75% of all of the issued and outstanding membership interests of UNEV Pipeline, LLC, the entity that owns the UNEV Pipeline.

“UNEV Pipeline” means, collectively, an approximately 400 mile, 12-inch refined products pipeline currently running from Woods Cross, Utah to Las Vegas, Nevada, related products terminals in or near Cedar City, Utah and Las Vegas, Nevada and other related assets owned by UNEV Pipeline, LLC.

“UNEV Profits Interest” means the membership interest in HEP UNEV held directly or indirectly by HFC.

“Voting Securities” means securities of any class of a Person entitling the holders thereof to vote on a regular basis in the election of members of the board of directors or other governing body of such Person.

“Wood Cross Operating” is defined in the introduction to this Agreement.

“Woods Cross Refinery Assets” has the meaning ascribed to the term “Assets” in that certain LLC Interest Purchase Agreement dated as of October 3, 2016 and effective as of October 1, 2016 by and among HollyFrontier Woods Cross, HFC and the Operating Partnership, pursuant to which HollyFrontier Woods Cross agreed to sell to the Operating Partnership all of the issued and outstanding limited liability company interests in Woods Cross Operating.

Exhibit C

to

Eighteenth Amended and Restated Omnibus Agreement

Interpretation

As used in this Agreement, unless a clear contrary intention appears:

(a)any reference to the singular includes the plural and vice versa, any reference to natural persons includes legal persons and vice versa, and any reference to a gender includes the other gender;

(b)the words “hereof”, “hereby”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement;

(c)any reference to Articles, Sections and Exhibits are, unless otherwise stated, references to Articles, Sections and Exhibits of or to this Agreement and references in any Section or definition to any clause means such clause of such Section or definition. The headings in this Agreement have been inserted for convenience only and shall not be taken into account in its interpretation;

(d)reference to any agreement (including this Agreement), document or instrument means such agreement, document, or instrument as amended, modified or supplemented and in effect from time to time in accordance with the terms thereof and, if applicable, the terms of this Agreement;

(e)the Exhibits hereto form an integral part of this Agreement and are equally binding therewith. Any reference to “this Agreement” shall include such Exhibits;

(f)references to a Person shall include any permitted assignee or successor to such Party in accordance with this Agreement and reference to a Person in a particular capacity excludes such Person in any other capacity;

(g)if any period is referred to in this Agreement by way of reference to a number of days, the days shall be calculated exclusively of the first and inclusively of the last day unless the last day falls on a day that is not a Business Day in which case the last day shall be the next succeeding Business Day;

(h)the use of “or” is not intended to be exclusive unless explicitly indicated otherwise;

(i)references to “$” or to “dollars” shall mean the lawful currency of the United States of America; and

(j)the words “includes,” “including,” or any derivation thereof shall mean “including without limitation” or “including, but not limited to.”

Exhibit D

to

Eighteenth Amended and Restated Omnibus Agreement

Asset Indemnification Summary

Part 1: Transferred Assets:

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
TRANSFERRED ASSET AND CLOSING DATE	HFC ENVIRONMENTAL (Expiration Date)	HEP ENVIRONMENTAL	RIGHT-OF-WAY	ADDITIONAL INDEMNITIES	OPERATIONAL INDEMNITY	RIGHT OF FIRST REFUSAL	INCLUDES TRANSFERRED TANKS
	Indemnity from HFC to HEP for Pre-Closing Covered Environmental Losses under Section 3.2(a) / Aggregate cap on HFC environmental indemnity in Section 3.1(b) (expiration date of indemnity)	Indemnity from HEP to HFC for Post-Closing Covered Environmental Losses under Section 3.4(a)	Right-of-Way Indemnity under Sections 3.2(a)(iii) and 3.2(a)(iv) (expiration date of indemnity)	Additional Indemnities under Section 3.2(a)(vi) (expiration date of indemnity)	Additional Indemnities under Section 3.5	Right of First Refusal under Article V
2004 Product Pipelines, Terminal and Related Assets (July 13, 2004)	$15,000,000 (July 13, 2014)	ü	ü (July 13, 2014)	ü (July 13, 2009)	ü	ü	No
8” and 10” Lovington/Artesia Intermediate Pipelines (June 1, 2009)	$2,500,000 (June 1, 2019)	ü	ü (June 1, 2019)	ü (June 1, 2014)	ü	ü	No

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
TRANSFERRED ASSET AND CLOSING DATE	HFC ENVIRONMENTAL (Expiration Date)	HEP ENVIRONMENTAL	RIGHT-OF-WAY	ADDITIONAL INDEMNITIES	OPERATIONAL INDEMNITY	RIGHT OF FIRST REFUSAL	INCLUDES TRANSFERRED TANKS
2008 Crude Pipelines, Tanks and Related Assets (March 1, 2008)	$7,500,000 (March 1, 2023)	ü	ü (March 1, 2023)	ü (March 1, 2013)	ü	ü	Yes
16” Lovington/Artesia Intermediate Pipeline (June 1, 2009)	None	ü	ü (June 1, 2019)	ü (June 1, 2014)	ü	ü	No
Tulsa Transferred Assets (August 1, 2009)	None	None	None	None	None	None	No
Beeson Pipeline (December 1, 2009)	None	ü	ü (December 1, 2019)	ü (December 1, 2014)	ü	ü	No
Roadrunner Pipeline (December 1, 2009)	None	ü	ü (December 1, 2019)	ü (December 1, 2014)	ü	ü	No
Additional Lovington Assets (March 31, 2010)	$15,000,000 (March 31, 2020)	ü	ü (March 31, 2020)	ü (March 31, 2015)	ü	ü	No
Additional Tulsa East Assets (March 31, 2010)	unlimited (no expiration)	None	None	None	None	ü	No
Sinclair Transferred Assets (October 19, 2009)	None	None	None	None	None	ü	Yes
Tulsa Interconnecting Pipelines (August 31, 2011)	None	ü	(August 31, 2021)	(August 31, 2016)	ü	ü	No

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
TRANSFERRED ASSET AND CLOSING DATE	HFC ENVIRONMENTAL (Expiration Date)	HEP ENVIRONMENTAL	RIGHT-OF-WAY	ADDITIONAL INDEMNITIES	OPERATIONAL INDEMNITY	RIGHT OF FIRST REFUSAL	INCLUDES TRANSFERRED TANKS
Cheyenne Assets (November 1, 2011)	$15,000,000 (November 1, 2021)	ü	ü (November 1, 2021)	ü (November 1, 2016)	ü	ü	Yes
El Dorado Assets (November 1, 2011)	$15,000,000 (November 1, 2021)	ü	ü (November 1, 2021)	ü (November 1, 2016)	ü	ü	Yes
UNEV Pipeline (July 12, 2012)	None	ü	ü (July 12, 2022)	ü (July 12, 2017)	ü	None	No
El Dorado Refinery Assets (November 1, 2015)	$15,000,000 (November 1, 2025)	ü	ü (November 1, 2025)	ü (November 1, 2020)	ü	ü	No
Osage (February 22, 2016)	None	None	None	None	None	None	No
Tulsa West Crude Tank Assets (11:59 p.m., March 31, 2016)	$5,000,000 (11:59 p.m., March 31, 2026)	ü	None	ü (11:59 p.m., March 31, 2021)	ü	ü	No
Woods Cross Refinery Assets October 1, 2016	$15,000,000 October 1, 2026	ü	ü October 1, 2026	ü October 1, 2026	ü	ü	No
North Loco Tanks (December 8, 2017)	None	None	None	None	None	ü	No

Part 2: Other Assets:

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
OTHER ASSET AND CLOSING DATE	HFC ENVIRONMENTAL (Expiration Date)	HEP ENVIRONMENTAL	RIGHT-OF-WAY	ADDITIONAL INDEMNITIES	OPERATIONAL INDEMNITY	RIGHT OF FIRST REFUSAL	INCLUDES TRANSFERRED TANKS
	Indemnity from HFC to HEP for Pre-Closing Covered Environmental Losses under Section 3.2(a) / Aggregate cap on HFC environmental indemnity in Section 3.1(b) (expiration date of indemnity)	Indemnity from HEP to HFC for Post-Closing Covered Environmental Losses under Section 3.4(a)	Right-of-Way Indemnity under Sections 3.2(a)(iii) and 3.2(a)(iv) (expiration date of indemnity)	Additional Indemnities under Section 3.2(a)(vi)(A) (expiration date of indemnity)1	Additional Indemnities under Section 3.5	Right of First Refusal under Article V
Malaga Pipeline System (July 16, 2013, as amended by that certain Amended and Restated Transportation Services Agreement dated September 26, 2014)	None	ü	None	None	ü	ü	No
El Dorado New Tank (Tank 647) (January 7, 2014)	None	ü	ü (January 7, 2024)	None	ü	ü	No
Artesia Rail Yard Facility (November 1, 2014)	None	ü	None	None	ü	ü	No
El Dorado Terminal (March 6, 2015)	None	ü	None	None	ü	ü	No

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
OTHER ASSET AND CLOSING DATE	HFC ENVIRONMENTAL (Expiration Date)	HEP ENVIRONMENTAL	RIGHT-OF-WAY	ADDITIONAL INDEMNITIES	OPERATIONAL INDEMNITY	RIGHT OF FIRST REFUSAL	INCLUDES TRANSFERRED TANKS
Beeson to Lovington System Expansion (March 12, 2015)	None	ü	None	None	ü	ü	No
Artesia Blending Facility (March 12, 2015)	None	ü	ü (March 12, 2025)	None	ü	ü	No
Cheyenne New Tank (Tank 117) (December 4, 2014)	None	ü	ü (December 4, 2029)	None	ü	ü	No
Tulsa New Tanks (Tanks 45 and 444A) (May 1, 2016)	None	ü	ü (May 1, 2026)	None	ü	ü	No
El Dorado New Tank (Tank 651) (September 12, 2016)	None	ü	ü (September 12, 2026)	None	ü	ü	No
SLC Pipeline (October 31, 2017)	None	None	None	None	None	ü	No
Frontier Aspen Pipeline (October 31, 2017)	None	None	None	None	None	ü	No
NWNAL Assets (October 31, 2017)	None	None	None	None	None	ü	No

Exhibit E

to

Eighteenth Amended and Restated Omnibus Agreement

General and Administrative Services

(1)Executive services

(2)Finance, including treasury, and administration services

(3)Information technology services

(4)Legal services

(5)Corporate health, safety and environmental services

(6)Human resources services

(7)Procurement

(8)Corporate operations team services

E-1

EX-10.52

Exhibit 10.52

HOLLYFRONTIER CORPORATION
PERFORMANCE SHARE UNIT AGREEMENT

(Section 162(m) Compliant)

This Performance Share Unit Agreement (the “Agreement”) is made and entered into by and between HollyFrontier Corporation, a Delaware corporation (the “Company”), and you. This Agreement is entered into as of the ___ day of [●], 2017 (the “Date of Grant”).

WITNESSETH:

WHEREAS, the Company has adopted the Plan (as defined below) to attract, retain and motivate employees, directors and consultants;

WHEREAS, the Compensation Committee (the “Committee”) believes that entering into this Agreement with you is consistent with the stated purposes for which the Plan was adopted; and

WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of this Agreement (“Agreement”) as if fully set forth herein and the terms capitalized but not defined herein or on Appendix A attached hereto shall have the meanings set forth in the Plan.

NOW, THEREFORE, in consideration of the services rendered by you, the parties agree as follows:

1.Grant. The Company hereby grants to you as of the Date of Grant a Performance Award of _________ shares of Phantom Stock consisting of performance share units (the “Performance Share Units”), subject to the terms and conditions set forth in this Agreement. Depending on the Company’s performance, you may earn from zero percent (0%) to two hundred percent (200%) of the Performance Share Units, based on the Company’s performance on two measures set forth in Section 3 over a designated performance period compared to the performance of a group of peer companies selected by the Committee.

2.The Plan. The Performance Share Units granted to you by this Agreement shall be granted under the HollyFrontier Corporation Long-Term Incentive Compensation Plan (the “Plan”).

3.Performance Period and Measures. This Section 3 sets forth the details of the Performance Award for the “Performance Period,” which begins on October 1 of the calendar year of the Date of Grant (“Year One”)and ends on September 30 of the third calendar year following Year One (“Year Three”). If you are employed by the Company or one of its Subsidiaries on December 15 of Year Three you will be entitled to a payment in Shares in the amount determined under Section 3(b) or pursuant to Section 4 or 5, as applicable, and payable at the time indicated in Section 6. The period of time beginning on the Date of Grant and ending on December 15 of Year Three is referred to herein as the “Service Period.”

(a)Performance Measures. The number of Performance Share Units earned for the Performance Period is determined by comparing the Company’s performance on the two measures

1

Exhibit 10.52

listed below over the Performance Period to the performance of the Peer Group over the Performance Period on the same two measures. The two performance measures are Return on Capital Employed and Total Shareholder Return.

(b)Shares Payable. The number of Shares payable is equal to the result of multiplying the total number of Performance Share Units awarded by the Performance Unit Payout Percentage. The number of Shares of Common Stock payable will be rounded down to the nearest Share. No fractional Shares of Common Stock will be issued pursuant to this Agreement.

4.Termination of Employment.

(a)In the event that your employment with the Company and its Subsidiaries terminates prior to December 15 of Year Three (i) due to your death, (ii) on account of your total and permanent disability, as determined by the Committee in its sole discretion or (iii) by action of the Company or its Subsidiary other than for Cause, you (or your beneficiary, if applicable) shall forfeit a number of the Performance Share Units equal to the number of Performance Share Units specified in Section 1 hereof times the percentage that (A) the number of days beginning on the day on which the date of such termination occurs and ending on the last day of the Service Period, (B) bears to the total number of days in the Service Period. In the event of such forfeiture, the number of Shares payable hereunder shall be equal to the result of multiplying the number of remaining Performance Share Units by the Performance Unit Payout Percentage determined as of the end of the Performance Period in accordance with Section 3. Shares payable pursuant to this Section 4(a) will be paid to you at the time specified in Section 6. Notwithstanding the foregoing, in the event your employment is terminated on account of death or disability, the Committee, in its sole discretion, may elect to make a payment to you pursuant to this Section 4(a) assuming a Performance Unit Payout Percentage of up to two hundred percent (200%) instead of the Performance Unit Payout Percentage that would otherwise be determined at the end of the Performance Period in accordance with Section 3; provided, that if the Committee elects to make such a payment, the amount will be paid to you no later than thirty (30) days following such election.

(b)If, prior to December 15 of Year Three you voluntarily separate from employment (other than due to your Retirement) or are terminated by the Company or a Subsidiary for Cause, all Performance Share Units awarded hereunder will be forfeited.

(c)With respect to the Performance Share Units, the Company or a Subsidiary may, in its sole discretion, determine that if you are on leave of absence for any reason you will be considered to still be in the employ of, or providing services to, the Company and its Subsidiaries, provided that your rights to the Performance Share Units, if any, during a Performance Period in which such a leave of absence occurs will be prorated to reflect the period of time during the Performance Period that you provided actual services to the Company and its Subsidiaries.

5.Special Involuntary Termination. In the event your employment with the Company and its Subsidiaries terminates due to a Special Involuntary Termination or your Retirement before December 15 of Year Three you will remain eligible to receive full payment hereunder (i.e., you will be treated as remaining continuously employed through December 15 of Year Three), and the number of Shares payable to you shall be that number determined pursuant to Section 3(b) hereof.

2

Exhibit 10.52

6.Payment of Performance Share Units. Except as otherwise provided in Section 4(a), the number of Shares payable hereunder shall be paid as soon as reasonably practicable after December 15 of Year Three but in no event later than two and one-half months following the end of Year Three, in the amount determined in accordance with Section 3, as adjusted by Section 4(a), if applicable. Such payment will be subject to withholding for taxes and other applicable payroll adjustments. The Committee’s determination of the amount payable shall be binding upon you and your beneficiary or estate. The value of such Shares shall not bear any interest owing to the passage of time. The number of Shares of Common Stock payable will be rounded down to the nearest Share. No fractional Shares of Common Stock will be issued pursuant to this Agreement.

7.Limited Stockholder Rights. The Performance Share Units granted pursuant to this Agreement do not and shall not entitle you to any rights of a holder of Shares, including the right to vote, prior to the date Shares are issued to you in settlement of the Performance Share Units pursuant to Section 6; provided, however, that in the event the Company declares and pays a dividend in respect of its outstanding Shares and, on the record date of that dividend, you hold Performance Share Units granted pursuant to this Agreement that have not been paid, the Company shall pay to you an amount in cash equal to the cash dividends you would have received if you were the holder of record as of such record date, of the number of Shares equal to the number of Performance Share Units specified in Section 1 hereof, such payment shall be made promptly following the date that the Company pays such dividend to its shareholders generally (however, in no event shall the payment be paid later than thirty (30) days following the date on which the Company pays such dividend to its shareholders generally). Your rights with respect to the Performance Share Units shall remain forfeitable at all times prior to the date on which the rights become vested and earned as set forth in Section 3, as adjusted by Section 4(a) or in accordance with Section 5, as applicable.

8.Adjustment in Number of Performance Share Units. The number of Performance Share Units subject to this Agreement shall be adjusted to reflect stock splits or other changes in the capital structure of the Company, all in accordance with the Plan. In the event that the outstanding Shares of the Company are exchanged for a different number or kind of shares or other securities, or if additional, new or different shares are distributed with respect to the Shares through merger, consolidation, or sale of all or substantially all of the assets of the Company, there shall be substituted for the Shares under the Performance Share Units subject to this Agreement the appropriate number and kind of shares of new or replacement securities as determined in the sole discretion of the Committee, subject to the terms and provisions of the Plan.

3

Exhibit 10.52

9.Compliance with Securities Law. Notwithstanding any provision of this Agreement to the contrary, the issuance of Shares will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Shares may then be listed. No Shares will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other law or regulations or the requirements of any stock exchange or market system upon which the Shares may then be listed. In addition, Shares will not be issued hereunder unless %2) a registration statement under the Securities Act, is at the time of issuance in effect with respect to the Shares issued or %2) in the opinion of legal counsel to the Company, the Shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any Shares subject to the Award will relieve the Company of any liability in respect of the failure to issue such Shares as to which such requisite authority has not been obtained. As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company. From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate Persons to make Shares available for issuance.

10.Payment of Taxes. The Company may require you to pay to the Company (or the Company’s Subsidiary if you are an employee of a Subsidiary of the Company), an amount the Company deems necessary to satisfy its (or its Subsidiary’s) current or future withholding with respect to federal, state or local income or other taxes that you incur as a result of the Award. With respect to any tax withholding and to the extent permissible pursuant to Rule 16b-3 under the Exchange Act, you may (a) direct the Company to withhold from the Shares to be issued to you under this Agreement the number of Shares necessary to satisfy the Company’s (or its Subsidiary’s) withholding of such taxes, which determination will be based on the Shares’ Fair Market Value at the time such determination is made; (b) deliver to the Company Shares sufficient to satisfy the Company’s (or its Subsidiary’s) tax withholding, based on the Shares’ Fair Market Value at the time such determination is made; or (c) deliver cash to the Company (or its Subsidiary) sufficient to satisfy its tax withholding obligations. If you desire to elect to use the stock withholding option described in subparagraph (a), you must make the election at the time and in the manner the Company prescribes and the maximum number of Shares that may be so withheld or surrendered shall be a number of Shares that have an aggregate Fair Market Value on the date of withholding or surrender of up to the aggregate amount of such tax liabilities determined based on the greatest withholding rates for federal, state, foreign and/or local tax purposes, including payroll taxes, that may be utilized without creating adverse accounting treatment with respect to the Award. The Company, in its discretion, may deny your request to satisfy its tax withholding obligations using a method described under subparagraph (a) or (b). In the event the Company determines that the aggregate Fair Market Value of the Shares withheld as payment of any tax withholding obligation is insufficient to discharge that tax withholding obligation, then you must pay to the Company (or its Subsidiary), in cash, the amount of that deficiency immediately upon the Company’s (or its Subsidiary’s) request.

4

Exhibit 10.52

11.Right of the Company and Subsidiaries to Terminate Services. Nothing in this Agreement confers upon you the right to continue in the employ of or performing services for the Company or any Subsidiary, or interfere in any way with the rights of the Company or any Subsidiary to terminate your employment or service relationship at any time.

12.Furnish Information. You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

13.Remedies. The Company shall be entitled to recover from you reasonable attorneys’ fees incurred in connection with the successful enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.

14.No Liability for Good Faith Determinations. The Company and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Performance Share Units granted hereunder.

15.Execution of Receipts and Releases. Any payment of cash or any issuance or transfer of Shares or other property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, will, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. In addition, the Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a general release of all claims in favor of the Company, any Affiliate and the employees, officers, stockholders or board members of the foregoing in such form as the Company may determine.

16.Clawback. This Agreement is subject to any written clawback policies that the Company, with the approval of the Board or the Committee, may adopt. Any such policy may subject your Performance Share Units and amounts paid or realized with respect to the Performance Share Units under this Agreement to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to this Agreement.

17.No Guarantee of Interests. The Board and the Company do not guarantee the Shares from loss or depreciation.

18.Company Records. Records of the Company or its Subsidiaries regarding your period of service, termination of service and the reason(s) therefor, leaves of absence, re-employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.

5

Exhibit 10.52

19.Notice. All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly addressed or if earlier the date it is sent via certified United States mail.

20.Waiver of Notice. Any person entitled to notice hereunder may waive such notice in writing.

21.Information Confidential. As partial consideration for the granting of the Award hereunder, you hereby agree to keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required by law and may be given in confidence to your spouse and tax and financial advisors. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor weighing against the advisability of granting any such future award to you. Nothing in this Agreement will prevent you from: (a) making a good faith report of possible violations of applicable law to any governmental agency or entity or (b) making disclosures that are protected under the whistleblower provisions of applicable law. For the avoidance of doubt, nothing herein shall prevent you from making a disclosure that: (i) is made (A) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. Further, an individual who files a lawsuit for retaliation by an employer of reporting a suspected violation of law may make disclosures without violating this Section 21 to the attorney of the individual and use such information in the court proceeding.

22.Successors. This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.

23.Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

24.Company Action. Any action required of the Company shall be by resolution of the Board or by a person or entity authorized to act by resolution of the Board.

25.Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

26.Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of Texas, without giving any effect to any conflict of law provisions thereof, except to the extent Texas state law is preempted by federal law. The obligation of the Company to sell and deliver Shares hereunder is subject to applicable

6

Exhibit 10.52

laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Shares.

27.Consent to Texas Jurisdiction and Venue. You hereby consent and agree that state courts located in Dallas, Texas and the United States District Court for the Northern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Company arising in connection with the Performance Share Units or this Agreement. In any dispute with the Company, you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.

28.Amendment. This Agreement may be amended the Board or by the Committee at any time (a) if the Board or the Committee determines, in its sole discretion, that amendment is necessary or advisable in light of any addition to or change in any federal or state, tax or securities law or other law or regulation, which change occurs after the Date of Grant and by its terms applies to the Award; or (b) other than in the circumstances described in clause (a) or provided in the Plan, with your consent.

29.The Plan. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.

30.Conflict. In the event the terms of this Agreement contradict the terms of any change in control agreement between you and the Company, the terms of this Agreement shall govern, subject to compliance with Section 409A of the Code.

31.Section 409A. It is intended that the Performance Share Units awarded hereunder shall comply with the requirements of Section 409A of the Code (and any regulations and guidelines issued thereunder), and this Agreement shall be interpreted on a basis consistent with such intent. Payments shall only be made on an event and in a manner permitted by Section 409A of the Code. Each payment under this Agreement is considered a separate payment for purposes of Section 409A of the Code. This Agreement may be amended without your consent in any respect deemed by the Committee to be necessary in order to preserve compliance with Section 409A of the Code. All payments to be made upon a termination of employment under this Agreement may only be made upon a “separation from service” under Section 409A of the Code. In no event may you, directly or indirectly, designate the calendar year of a payment. Notwithstanding anything in this Agreement to the contrary, if you are a “specified employee” under Section 409A of the Code at the time of separation from service and if payment of any amount under this Agreement is required to be delayed for a period of six months after the separation from service pursuant to Section 409A of the Code, payment of such amount shall be delayed as required by Section 409A of the Code, and the accumulated postponed amount shall be paid in a lump sum payment within 10 days after the end of the six-month period. If you die during the postponement period prior to the payment of postponed amount, the accumulated postponed amount shall be paid to the personal representative of your estate within 60 days after the date of your death.

32.Nontransferability of Agreement. This Agreement and all rights under this Agreement shall not be transferable by you during your life other than by will or pursuant to applicable laws of descent and distribution. Any of your rights and privileges in connection herewith

7

Exhibit 10.52

shall not be transferred, assigned, pledged or hypothecated by you or by any other person or persons, in any way, whether by operation of law, or otherwise, and shall not be subject to execution, attachment, garnishment or similar process. In the event of any such occurrence, this Agreement shall automatically be terminated and shall thereafter be null and void. Notwithstanding the foregoing, all or some of the Performance Share Units or rights under this Agreement may be transferred to a spouse pursuant to a domestic relations order issued by a court of competent jurisdiction.

HollyFrontier Corporation

George J. Damiris, Chief Executive Officer and President

8

Exhibit 10.52

Appendix A

Defined Terms

For purposes of the Agreement, the following terms shall have the meanings assigned below:

“Adverse Change” means (i) a change in the city in which you are required to work regularly, (ii) a substantial increase in travel requirements of employment, (iii) a substantial reduction in duties of the type previously performed by you, or (iv) a significant reduction in your compensation or benefits (other than bonuses and other discretionary items of compensation) that does not apply generally to employees of the Company or its successor.

“Affiliate” has the meaning provided in Rule 12b-2 under the Exchange Act.

“Beneficial Owner” has the meaning provided in Rule 13d-3 under the Exchange Act.

“Cause” means:

(i)An act or acts of dishonesty on your part constituting a felony or serious misdemeanor and resulting or intended to result directly in gain or personal enrichment at the expense of the Company or any of its Subsidiaries;

(ii)Gross or willful and wanton negligence in the performance of your material and substantial duties of employment with the Company or any of its Subsidiaries; or

(iii)Your conviction of a felony involving moral turpitude.

The existence of Cause shall be determined by the Committee, in its sole and absolute discretion.

“Change in Control” means the occurrence of any of the following after the Date of Grant:

(i)    Any Person, other than (A) the Company or any of its Subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company, is or becomes the Beneficial Owner, directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates) representing more than 40% of the combined voting power of the Company’s then outstanding securities, or more than 40% of the then outstanding common stock of the Company, excluding any Person who becomes such a Beneficial Owner in connection with a transaction described in clause (iii)(A) below.

(ii)    The individuals who as of the Date of Grant constitute the Board and any New Director cease for any reason to constitute a majority of the Board.

9

Exhibit 10.52

(iii)    There is consummated a merger or consolidation of the Company or any direct or indirect Subsidiary of the Company with any other corporation, except if:

(A)    the merger or consolidation results in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60% of the combined voting power of the voting securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation; or

(B)    the merger or consolidation is effected to implement a recapitalization of the Company (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly, or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates other than in connection with the acquisition by the Company or its Affiliates of a business) representing more than 40% of the combined voting power of the Company’s then outstanding securities.

(iv)    The stockholders of the Company approve a plan of complete liquidation or dissolution of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity at least 60% of the combined voting power of the voting securities of which is owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.

“New Director” means an individual whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds of the directors then still in office who either were directors at the Date of Grant or whose election or nomination for election was previously so approved or recommended. However, “New Director” shall not include a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation relating to the election of directors of the Company.

“Peer Group” means Andeavor, CVR Energy, Inc., Delek U.S. Holdings, Inc., Marathon Petroleum Corporation, PBF Energy Corporation, Phillips 66, and Valero Energy Corporation. If a member of the Peer Group ceases to be a public company during the Performance Period (whether by merger, consolidation, liquidation or otherwise) or it fails to file financial statements with the SEC in a timely manner, it shall be treated as if it had not been a Peer Group member for the entire Performance Period.

“Performance Unit Payout Percentage” means the percentile obtained by dividing the sum of (1) the ROCE Performance Percentage and (2) the TSR Performance Percentage, by two.

“Person” has the meaning given in section 3(a)(9) of the Exchange Act as modified and used in sections 13(d) and 14(d) of the Exchange Act.

10

Exhibit 10.52

“Retirement” means your termination of employment other than for Cause on or after the date on which you: (i) have achieved ten years of continuous service with the Company and its Subsidiaries, and(ii) are age sixty (60).

“Return on Capital Employed,” or ROCE, is defined as (i) operating income before depreciation and amortization divided by (ii) the sum of shareholders’ equity, plus minority interest, plus debt, less goodwill and intangible assets, less cash and marketable securities at the beginning of the Performance Period; provided, that such metric will be calculated to exclude (a) any gains or losses attributable to FIFO inventory valuation (including lower of cost or market adjustments), (b) the effects of impairment expense related to intangible assets, including goodwill, and (c) non-cash asset writedowns; provided, further, the Committee may exclude the impact of any of the following events or occurrences (with respect to the Company or any member of the Peer Group) which the Committee determines should appropriately be excluded: (A) asset write-downs; (B) litigation, claims, judgments or settlements; (C) the effect of changes in tax law or other such laws or regulations affecting reported results; (D) accruals for reorganization and restructuring programs; (E) any extraordinary, unusual or nonrecurring items as described in the Accounting Standards Codification Topic 225, as the same may be amended or superseded from time to time; (F) any change in accounting principles as defined in the Accounting Standards Codification Topic 250, as the same may be amended or superseded from time to time; (G) any loss from a discontinued operation as described in the Accounting Standards Codification Topic 360, as the same may be amended or superseded from time to time; (H) adjustments to ROCE of the Company or any member (or multiple members) of the Peer Group to reflect mergers, acquisitions, purchases or similar transactions as necessary to prevent the increase or decrease of the ROCE of the Company or member of the Peer Group related to the merger, acquisition, purchase or similar transaction; (I) third party expenses associated with acquisitions; and (J) to the extent set forth with reasonable particularity in connection with the establishment of performance goals, any other extraordinary events or occurrences identified by the Committee.

“ROCE Performance Percentage” means the percentage set forth in the table below determined in accordance with the ordinal ranking of the Return on Capital Employed of the Company compared to the ROCE of each entity in the Peer Group achieved during the Performance Period:

Ranking of the Company within Peer Group	ROCE Performance Percentage
First	Maximum (200% of Target)
Second	167% of Target
Between Second and Target	Interpolate between 100% and 167%
Average of Fourth and Fifth	Target (100%)
Between Seventh and Target	Interpolate between 50% and 100%
Seventh	50% of Target (Minimum)
Eighth (last)	Zero

In the event the Peer Group contains fewer than seven companies at the end of the Performance Period, the table above will be adjusted by the Committee in a manner consistent with the table above to reflect the change in the number of companies within the Peer Group.

11

Exhibit 10.52

“SEC” means the Securities and Exchange Commission.

“Special Involuntary Termination” means the occurrence of (1) or (2) below within 60 days prior to, or at any time after, a Change in Control, where (1) is termination of your employment with the Company (including Subsidiaries of the Company) by the Company for any reason other than Cause and (2) is your resignation from employment with the Company (including Subsidiaries of the Company) within 90 days after an Adverse Change by the Company (including Subsidiaries of the Company) in the terms of your employment.

“Total Shareholder Return” or TSR, means (A) the sum of (1) share price appreciation (calculated as the closing share price of the Common Stock for the last business day of the Performance Period less the closing share price of the Common Stock for the first business day of the Performance Period), plus (2) cumulative dividends during the Performance Period, plus (3) any additional value or compensation received by shareholders such as stock received from spinoffs, divided by (B) the closing share price of the Common Stock on the first business day of the Performance Period.

“TSR Performance Percentage” means the percentage set forth in the table below determined in accordance with the ordinal ranking of the Total Shareholder Return of the Company compared to the TSR of each entity in the Peer Group achieved during the Performance Period:

Ranking of the Company within Peer Group	TSR Performance Percentage
First	Maximum (200% of Target)
Second	167% of Target
Between Second and Target	Interpolate between 100% and 167%
Average of Fourth and Fifth	Target (100%)
Between Seventh and Target	Interpolate between 50% and 100%
Seventh	50% of Target (Minimum)
Eighth (last)	Zero

In the event the Peer Group contains fewer than seven companies at the end of the Performance Period, the table above will be adjusted by the Committee in a manner consistent with the table above to reflect the change in the number of companies within the Peer Group.

12

EX-10.53

Exhibit 10.53    

HOLLYFRONTIER CORPORATION
PERFORMANCE SHARE UNIT AGREEMENT
(Non-Section 162(m))

This Performance Share Unit Agreement (the “Agreement”) is made and entered into by and between HollyFrontier Corporation, a Delaware corporation (the “Company”), and you. This Agreement is entered into as of the ___ day of [●], 2017 (the “Date of Grant”).

WITNESSETH:

WHEREAS, the Company has adopted the Plan (as defined below) to attract, retain and motivate employees, directors and consultants;

WHEREAS, the Compensation Committee (the “Committee”) believes that entering into this Agreement with you is consistent with the stated purposes for which the Plan was adopted; and

WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of this Agreement (“Agreement”) as if fully set forth herein and the terms capitalized but not defined herein or on Appendix A attached hereto shall have the meanings set forth in the Plan.

NOW, THEREFORE, in consideration of the services rendered by you, the parties agree as follows:

1.Grant. The Company hereby grants to you as of the Date of Grant a Performance Award of _________ shares of Phantom Stock consisting of performance share units (the “Performance Share Units”), subject to the terms and conditions set forth in this Agreement. Depending on the Company’s performance, you may earn from zero percent (0%) to two hundred percent (200%) of the Performance Share Units, based on the Company’s performance on two measures set forth in Section 3 over a designated performance period compared to the performance of a group of peer companies selected by the Committee.

2.The Plan. The Performance Share Units granted to you by this Agreement shall be granted under the HollyFrontier Corporation Long-Term Incentive Compensation Plan (the “Plan”).

3.Performance Period and Measures. This Section 3 sets forth the details of the Performance Award for the “Performance Period,” which begins on October 1 of the calendar year of the Date of Grant (“Year One”)and ends on September 30 of the third calendar year following Year One (“Year Three”). If you are employed by the Company or one of its Subsidiaries on December 15 of Year Three you will be entitled to a payment in Shares in the amount determined under Section 3(b) or pursuant to Section 4(a), as applicable, and payable at the time indicated in Section 5.

(a)Performance Measures. The number of Performance Share Units earned for the Performance Period is determined by comparing the Company’s performance on the two measures listed below over the Performance Period to the performance of the Peer Group over the Performance

1

Period on the same two measures. The two performance measures are Return on Capital Employed and Total Shareholder Return.

(b)Shares Payable. The number of Shares payable is equal to the result of multiplying the total number of Performance Share Units awarded by the Performance Unit Payout Percentage. The number of Shares of Common Stock payable will be rounded down to the nearest Share. No fractional Shares of Common Stock will be issued pursuant to this Agreement.

4.Termination of Employment.

(a)In the event that your employment with the Company and its Subsidiaries terminates prior to December 15 of Year Three (i) due to your death, (ii) on account of your total and permanent disability, as determined by the Committee in its sole discretion, (iii) as a result of a Special Involuntary Termination or (iv) due to your Retirement, the Performance Share Units will become immediately vested and nonforfeitable assuming a Performance Unit Payout Percentage of one hundred percent (100%) instead of the Performance Unit Payout Percentage that would otherwise be determined at the end of the Performance Period in accordance with Section 3.

(b)If, prior to December 15 of Year Three you voluntarily separate from employment (other than due to your Retirement) or are terminated by action of the Company or a Subsidiary (other than a Special Involuntary Termination), including if you are terminated by the Company or a Subsidiary for Cause, all Performance Share Units awarded hereunder will be forfeited.

(c)With respect to the Performance Share Units, the Company or a Subsidiary may, in its sole discretion, determine that if you are on leave of absence for any reason you will be considered to still be in the employ of, or providing services to, the Company and its Subsidiaries, provided that your rights to the Performance Share Units, if any, during a Performance Period in which such a leave of absence occurs will be prorated to reflect the period of time during the Performance Period that you provided actual services to the Company and its Subsidiaries.

5.Payment of Performance Share Units. The number of Shares payable hereunder shall be paid as soon as reasonably practicable after December 15 of Year Three but in no event later than two and one-half months following the end of Year Three, in the amount determined in accordance with Section 3; provided, however, in the event of your termination of employment with the Company and its Subsidiaries pursuant to Section 4(a) the Shares shall be paid within thirty (30) days following such termination of employment. Such payment will be subject to withholding for taxes and other applicable payroll adjustments. The Committee’s determination of the amount payable shall be binding upon you and your beneficiary or estate. The value of such Shares shall not bear any interest owing to the passage of time. The number of Shares of Common Stock payable will be rounded down to the nearest Share. No fractional Shares of Common Stock will be issued pursuant to this Agreement.

6.Limited Stockholder Rights. The Performance Share Units granted pursuant to this Agreement do not and shall not entitle you to any rights of a holder of Shares, including the right to vote, prior to the date Shares are issued to you in settlement of the Performance Share Units pursuant to Section 5; provided, however, that in the event the Company declares and pays a dividend

2

in respect of its outstanding Shares and, on the record date of that dividend, you hold Performance Share Units granted pursuant to this Agreement that have not been paid, the Company shall pay to you an amount in cash equal to the cash dividends you would have received if you were the holder of record as of such record date, of the number of Shares equal to the number of Performance Share Units specified in Section 1 hereof, such payment shall be made promptly following the date that the Company pays such dividend to its shareholders generally (however, in no event shall the payment be paid later than thirty (30) days following the date on which the Company pays such dividend to its shareholders generally). Your rights with respect to the Performance Share Units shall remain forfeitable at all times prior to the date on which the rights become vested and earned as set forth in Section 3, as adjusted by Section 4(a), as applicable.

7.Adjustment in Number of Performance Share Units. The number of Performance Share Units subject to this Agreement shall be adjusted to reflect stock splits or other changes in the capital structure of the Company, all in accordance with the Plan. In the event that the outstanding Shares of the Company are exchanged for a different number or kind of shares or other securities, or if additional, new or different shares are distributed with respect to the Shares through merger, consolidation, or sale of all or substantially all of the assets of the Company, there shall be substituted for the Shares under the Performance Share Units subject to this Agreement the appropriate number and kind of shares of new or replacement securities as determined in the sole discretion of the Committee, subject to the terms and provisions of the Plan.

8.Compliance with Securities Law. Notwithstanding any provision of this Agreement to the contrary, the issuance of Shares will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Shares may then be listed. No Shares will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other law or regulations or the requirements of any stock exchange or market system upon which the Shares may then be listed. In addition, Shares will not be issued hereunder unless %2) a registration statement under the Securities Act, is at the time of issuance in effect with respect to the Shares issued or %2) in the opinion of legal counsel to the Company, the Shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any Shares subject to the Award will relieve the Company of any liability in respect of the failure to issue such Shares as to which such requisite authority has not been obtained. As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company. From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate Persons to make Shares available for issuance.

9.Payment of Taxes. The Company may require you to pay to the Company (or the Company’s Subsidiary if you are an employee of a Subsidiary of the Company), an amount the

3

Company deems necessary to satisfy its (or its Subsidiary’s) current or future withholding with respect to federal, state or local income or other taxes that you incur as a result of the Award. With respect to any tax withholding and to the extent permissible pursuant to Rule 16b-3 under the Exchange Act, you may (a) direct the Company to withhold from the Shares to be issued to you under this Agreement the number of Shares necessary to satisfy the Company’s (or its Subsidiary’s) withholding of such taxes, which determination will be based on the Shares’ Fair Market Value at the time such determination is made; (b) deliver to the Company Shares sufficient to satisfy the Company’s (or its Subsidiary’s) tax withholding, based on the Shares’ Fair Market Value at the time such determination is made; or (c) deliver cash to the Company (or its Subsidiary) sufficient to satisfy its tax withholding obligations. If you desire to elect to use the stock withholding option described in subparagraph (a), you must make the election at the time and in the manner the Company prescribes and the maximum number of Shares that may be so withheld or surrendered shall be a number of Shares that have an aggregate Fair Market Value on the date of withholding or surrender of up to the aggregate amount of such tax liabilities determined based on the greatest withholding rates for federal, state, foreign and/or local tax purposes, including payroll taxes, that may be utilized without creating adverse accounting treatment with respect to the Award. The Company, in its discretion, may deny your request to satisfy its tax withholding obligations using a method described under subparagraph (a) or (b). In the event the Company determines that the aggregate Fair Market Value of the Shares withheld as payment of any tax withholding obligation is insufficient to discharge that tax withholding obligation, then you must pay to the Company (or its Subsidiary), in cash, the amount of that deficiency immediately upon the Company’s (or its Subsidiary’s) request.

10.Right of the Company and Subsidiaries to Terminate Services. Nothing in this Agreement confers upon you the right to continue in the employ of or performing services for the Company or any Subsidiary, or interfere in any way with the rights of the Company or any Subsidiary to terminate your employment or service relationship at any time.

11.Furnish Information. You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

12.Remedies. The Company shall be entitled to recover from you reasonable attorneys’ fees incurred in connection with the successful enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.

13.No Liability for Good Faith Determinations. The Company and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Performance Share Units granted hereunder.

14.Execution of Receipts and Releases. Any payment of cash or any issuance or transfer of Shares or other property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, will, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. In addition, the Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a general

4

release of all claims in favor of the Company, any Affiliate and the employees, officers, stockholders or board members of the foregoing in such form as the Company may determine.

15.Clawback. This Agreement is subject to any written clawback policies that the Company, with the approval of the Board or the Committee, may adopt. Any such policy may subject your Performance Share Units and amounts paid or realized with respect to the Performance Share Units under this Agreement to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to this Agreement.

16.No Guarantee of Interests. The Board and the Company do not guarantee the Shares from loss or depreciation.

17.Company Records. Records of the Company or its Subsidiaries regarding your period of service, termination of service and the reason(s) therefor, leaves of absence, re-employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.

18.Notice. All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly addressed or if earlier the date it is sent via certified United States mail.

19.Waiver of Notice. Any person entitled to notice hereunder may waive such notice in writing.

20.Information Confidential. As partial consideration for the granting of the Award hereunder, you hereby agree to keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required by law and may be given in confidence to your spouse and tax and financial advisors. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor weighing against the advisability of granting any such future award to you. Nothing in this Agreement will prevent you from: (a) making a good faith report of possible violations of applicable law to any governmental agency or entity or (b) making disclosures that are protected under the whistleblower provisions of applicable law. For the avoidance of doubt, nothing herein shall prevent you from making a disclosure that: (i) is made (A) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. Further, an individual who files a lawsuit for retaliation by an employer of reporting a suspected violation of law may make

5

disclosures without violating this Section 20 to the attorney of the individual and use such information in the court proceeding.

21.Successors. This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.

22.Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

23.Company Action. Any action required of the Company shall be by resolution of the Board or by a person or entity authorized to act by resolution of the Board.

24.Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

25.Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of Texas, without giving any effect to any conflict of law provisions thereof, except to the extent Texas state law is preempted by federal law. The obligation of the Company to sell and deliver Shares hereunder is subject to applicable laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Shares.

26.Consent to Texas Jurisdiction and Venue. You hereby consent and agree that state courts located in Dallas, Texas and the United States District Court for the Northern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Company arising in connection with the Performance Share Units or this Agreement. In any dispute with the Company, you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.

27.Amendment. This Agreement may be amended the Board or by the Committee at any time (a) if the Board or the Committee determines, in its sole discretion, that amendment is necessary or advisable in light of any addition to or change in any federal or state, tax or securities law or other law or regulation, which change occurs after the Date of Grant and by its terms applies to the Award; or (b) other than in the circumstances described in clause (a) or provided in the Plan, with your consent.

28.The Plan. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.

29.Conflict. In the event the terms of this Agreement contradict the terms of any change in control agreement between you and the Company, the terms of this Agreement shall govern, subject to compliance with Section 409A of the Code.

6

30.Section 409A. It is intended that the Performance Share Units awarded hereunder shall comply with the requirements of Section 409A of the Code (and any regulations and guidelines issued thereunder), and this Agreement shall be interpreted on a basis consistent with such intent. Payments shall only be made on an event and in a manner permitted by Section 409A of the Code. Each payment under this Agreement is considered a separate payment for purposes of Section 409A of the Code. This Agreement may be amended without your consent in any respect deemed by the Committee to be necessary in order to preserve compliance with Section 409A of the Code. All payments to be made upon a termination of employment under this Agreement may only be made upon a “separation from service” under Section 409A of the Code. In no event may you, directly or indirectly, designate the calendar year of a payment. Notwithstanding anything in this Agreement to the contrary, if you are a “specified employee” under Section 409A of the Code at the time of separation from service and if payment of any amount under this Agreement is required to be delayed for a period of six months after the separation from service pursuant to Section 409A of the Code, payment of such amount shall be delayed as required by Section 409A of the Code, and the accumulated postponed amount shall be paid in a lump sum payment within 10 days after the end of the six-month period. If you die during the postponement period prior to the payment of postponed amount, the accumulated postponed amount shall be paid to the personal representative of your estate within 60 days after the date of your death.

31.Nontransferability of Agreement. This Agreement and all rights under this Agreement shall not be transferable by you during your life other than by will or pursuant to applicable laws of descent and distribution. Any of your rights and privileges in connection herewith shall not be transferred, assigned, pledged or hypothecated by you or by any other person or persons, in any way, whether by operation of law, or otherwise, and shall not be subject to execution, attachment, garnishment or similar process. In the event of any such occurrence, this Agreement shall automatically be terminated and shall thereafter be null and void. Notwithstanding the foregoing, all or some of the Performance Share Units or rights under this Agreement may be transferred to a spouse pursuant to a domestic relations order issued by a court of competent jurisdiction.

HollyFrontier Corporation

George J. Damiris, Chief Executive Officer and President

7

Appendix A

Defined Terms

For purposes of the Agreement, the following terms shall have the meanings assigned below:

“Adverse Change” means (i) a change in the city in which you are required to work regularly, (ii) a substantial increase in travel requirements of employment, (iii) a substantial reduction in duties of the type previously performed by you, or (iv) a significant reduction in your compensation or benefits (other than bonuses and other discretionary items of compensation) that does not apply generally to employees of the Company or its successor.

“Affiliate” has the meaning provided in Rule 12b-2 under the Exchange Act.

“Beneficial Owner” has the meaning provided in Rule 13d-3 under the Exchange Act.

“Cause” means:

(i)An act or acts of dishonesty on your part constituting a felony or serious misdemeanor and resulting or intended to result directly in gain or personal enrichment at the expense of the Company or any of its Subsidiaries;

(ii)Gross or willful and wanton negligence in the performance of your material and substantial duties of employment with the Company or any of its Subsidiaries; or

(iii)Your conviction of a felony involving moral turpitude.

The existence of Cause shall be determined by the Committee, in its sole and absolute discretion.

“Change in Control” means the occurrence of any of the following after the Date of Grant:

(i)    Any Person, other than (A) the Company or any of its Subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company, is or becomes the Beneficial Owner, directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates) representing more than 40% of the combined voting power of the Company’s then outstanding securities, or more than 40% of the then outstanding common stock of the Company, excluding any Person who becomes such a Beneficial Owner in connection with a transaction described in clause (iii)(A) below.

(ii)    The individuals who as of the Date of Grant constitute the Board and any New Director cease for any reason to constitute a majority of the Board.

8

(iii)    There is consummated a merger or consolidation of the Company or any direct or indirect Subsidiary of the Company with any other corporation, except if:

(A)    the merger or consolidation results in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60% of the combined voting power of the voting securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation; or

(B)    the merger or consolidation is effected to implement a recapitalization of the Company (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly, or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates other than in connection with the acquisition by the Company or its Affiliates of a business) representing more than 40% of the combined voting power of the Company’s then outstanding securities.

(iv)    The stockholders of the Company approve a plan of complete liquidation or dissolution of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity at least 60% of the combined voting power of the voting securities of which is owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.

“New Director” means an individual whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds of the directors then still in office who either were directors at the Date of Grant or whose election or nomination for election was previously so approved or recommended. However, “New Director” shall not include a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation relating to the election of directors of the Company.

“Peer Group” means Andeavor, CVR Energy, Inc., Delek U.S. Holdings, Inc., Marathon Petroleum Corporation, PBF Energy Corporation, Phillips 66, and Valero Energy Corporation. If a member of the Peer Group ceases to be a public company during the Performance Period (whether by merger, consolidation, liquidation or otherwise) or it fails to file financial statements with the SEC in a timely manner, it shall be treated as if it had not been a Peer Group member for the entire Performance Period.

“Performance Unit Payout Percentage” means the percentile obtained by dividing the sum of (1) the ROCE Performance Percentage and (2) the TSR Performance Percentage, by two.

“Person” has the meaning given in section 3(a)(9) of the Exchange Act as modified and used in sections 13(d) and 14(d) of the Exchange Act.

9

“Retirement” means your termination of employment other than for Cause on or after the date on which you: (i) have achieved ten years of continuous service with the Company and its Subsidiaries, and(ii) are age sixty (60).

“Return on Capital Employed,” or ROCE, is defined as (i) operating income before depreciation and amortization divided by (ii) the sum of shareholders’ equity, plus minority interest, plus debt, less goodwill and intangible assets, less cash and marketable securities at the beginning of the Performance Period; provided, that such metric will be calculated to exclude (a) any gains or losses attributable to FIFO inventory valuation (including lower of cost or market adjustments), (b) the effects of impairment expense related to intangible assets, including goodwill, and (c) non-cash asset writedowns; provided, further, the Committee may exclude the impact of any of the following events or occurrences (with respect to the Company or any member of the Peer Group) which the Committee determines should appropriately be excluded: (A) asset write-downs; (B) litigation, claims, judgments or settlements; (C) the effect of changes in tax law or other such laws or regulations affecting reported results; (D) accruals for reorganization and restructuring programs; (E) any extraordinary, unusual or nonrecurring items as described in the Accounting Standards Codification Topic 225, as the same may be amended or superseded from time to time; (F) any change in accounting principles as defined in the Accounting Standards Codification Topic 250, as the same may be amended or superseded from time to time; (G) any loss from a discontinued operation as described in the Accounting Standards Codification Topic 360, as the same may be amended or superseded from time to time; (H) adjustments to ROCE of the Company or any member (or multiple members) of the Peer Group to reflect mergers, acquisitions, purchases or similar transactions as necessary to prevent the increase or decrease of the ROCE of the Company or member of the Peer Group related to the merger, acquisition, purchase or similar transaction; (I) third party expenses associated with acquisitions; and (J) to the extent set forth with reasonable particularity in connection with the establishment of performance goals, any other extraordinary events or occurrences identified by the Committee.

“ROCE Performance Percentage” means the percentage set forth in the table below determined in accordance with the ordinal ranking of the Return on Capital Employed of the Company compared to the ROCE of each entity in the Peer Group achieved during the Performance Period:

Ranking of the Company within Peer Group	ROCE Performance Percentage
First	Maximum (200% of Target)
Second	167% of Target
Between Second and Target	Interpolate between 100% and 167%
Average of Fourth and Fifth	Target (100%)
Between Seventh and Target	Interpolate between 50% and 100%
Seventh	50% of Target (Minimum)
Eighth (last)	Zero

“SEC” means the Securities and Exchange Commission.

10

“Special Involuntary Termination” means the occurrence of (1) or (2) below within 60 days prior to, or at any time after, a Change in Control, where (1) is termination of your employment with the Company (including Subsidiaries of the Company) by the Company for any reason other than Cause and (2) is your resignation from employment with the Company (including Subsidiaries of the Company) within 90 days after an Adverse Change by the Company (including Subsidiaries of the Company) in the terms of your employment.

“Total Shareholder Return” or TSR, means (A) the sum of (1) share price appreciation (calculated as the closing share price of the Common Stock for the last business day of the Performance Period less the closing share price of the Common Stock for the first business day of the Performance Period), plus (2) cumulative dividends during the Performance Period, plus (3) any additional value or compensation received by shareholders such as stock received from spinoffs, divided by (B) the closing share price of the Common Stock on the first business day of the Performance Period.

“TSR Performance Percentage” means the percentage set forth in the table below determined in accordance with the ordinal ranking of the Total Shareholder Return of the Company compared to the TSR of each entity in the Peer Group achieved during the Performance Period:

Ranking of the Company within Peer Group	TSR Performance Percentage
First	Maximum (200% of Target)
Second	167% of Target
Between Second and Target	Interpolate between 100% and 167%
Average of Fourth and Fifth	Target (100%)
Between Seventh and Target	Interpolate between 50% and 100%
Seventh	50% of Target (Minimum)
Eighth (last)	Zero

In the event the Peer Group contains fewer than seven companies at the end of the Performance Period, the table above will be adjusted by the Committee in a manner consistent with the table above to reflect the change in the number of companies within the Peer Group.

11

EX-10.58

HOLLYFRONTIER CORPORATION

RESTRICTED STOCK UNIT AGREEMENT

(Time-Based Vesting)

This Agreement is made and entered into as of the Date of Grant set forth in the Notice of Grant of Restricted Stock Units (“Notice of Grant”) by and between HollyFrontier Corporation, a Delaware corporation (the “Company”), and you;

WHEREAS, the Company, as part of your compensation for services to the Company and its Subsidiaries and in order to induce you to materially contribute to the success of the Company, agrees to grant you this restricted stock unit award;

WHEREAS, the Company adopted the Plan (as defined in the Notice of Grant) under which the Company is authorized to grant stock units and phantom stock awards, as applicable (in each case, herein referred to as restricted stock units) to certain employees, directors and other service providers of the Company and its Subsidiaries;

WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of this Restricted Stock Unit Agreement (Time-Based Vesting) (“Agreement”) as if fully set forth herein and the terms capitalized but not defined herein shall have the meanings set forth in the Plan; and

WHEREAS, you desire to accept the restricted stock unit award made pursuant to this Agreement.

NOW, THEREFORE, in consideration of the mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the parties hereto agree as follows:

1.The Grant. Subject to the conditions set forth below, the Company hereby grants you effective as of the Date of Grant set forth in the Notice of Grant, as a matter of separate inducement but not in lieu of any cash or other compensation for your services for the Company (or any Subsidiary), an award (the “Award”) covering the aggregate number of Shares set forth in the Notice of Grant in accordance with the terms and conditions set forth herein, in the Notice of Grant and in the Plan, plus the additional rights to receive possible dividend equivalents, in accordance with the terms and conditions set forth herein.

2.No Shareholder Rights. The Restricted Stock Units (“RSUs”) granted pursuant to this Agreement do not and shall not entitle you to any rights of a holder of Shares prior to the date Shares are issued to you in settlement of the Award.

3.Dividend Equivalents. In the event that the Company declares and pays a dividend in respect of its outstanding Shares on or after the Date of Grant and, on the record date for such dividend, you hold RSUs granted pursuant to this Agreement that have not been settled, the Company shall pay to you an amount in cash equal to the cash dividends you would have received if you were the holder of record as of such record date, of the number of Shares related to the portion of your

1

RSUs that have not been settled as of such record date, such payment (“Dividend Equivalents”) to be made on or promptly following the date that the Company pays such dividend (however, in no event shall the Dividend Equivalents be paid later than 30 days following the date on which the Company pays such dividend to its shareholders generally).

4.Restrictions; Forfeiture. The RSUs are restricted in that they cannot be sold, transferred or otherwise alienated or hypothecated until Shares related to such RSUs are issued pursuant to Section 8 following the removal or expiration of the restrictions as contemplated in Section 5 (and Section 6, if applicable) of this Agreement and as described in the Notice of Grant. In the event you cease to be an employee of the Company and any Subsidiary, other than as provided in Section 6 below, the RSUs that are not vested on the date of such cessation of employment shall be immediately forfeited.

5.Expiration of Restrictions and Risk of Forfeiture. The restrictions on the RSUs granted pursuant to this Agreement will expire and the RSUs will become nonforfeitable as set forth in the Notice of Grant, provided that you remain an employee of the Company and its Subsidiaries until the applicable dates and times set forth therein. RSUs that have become vested and non-forfeitable as provided in this Agreement are referred to herein as “Vested.”

6.Termination of Employment.

(a)Termination Generally. Subject to subsections (b), (c), (d) and (e) below, if your employment relationship with the Company and its Subsidiaries is terminated for any reason, then those RSUs that have not become Vested as of the date of termination shall become null and void and those RSUs shall be forfeited to the Company. The RSUs that are Vested as of the date of such termination shall not be forfeited to the Company and will be settled in accordance with Section 8.

(b)Death or Disability. In the event of termination of your employment due to your (i) death or (ii) total and permanent disability, as determined by the Committee in its sole discretion, in either case, before all of the RSUs granted pursuant to this Agreement have become Vested, you will forfeit a number of RSUs equal to the number of RSUs specified in the Notice of Grant times the percentage that (A) the number of days beginning on the day on which the termination due to death or disability occurs and ending on the last day of the Service Period, (B) bears to the total number of days in the Service Period, and any remaining RSUs that are not vested will become Vested; provided, however, that any fractional RSUs will become null and void and automatically forfeited.

(c)Retirement. In the event of termination of your employment with the Company and its Subsidiaries due to your Retirement before all of the RSUs have become Vested, the RSUs granted pursuant to this Agreement that have not become Vested as of such date of termination shall become Vested on such date of termination.

(d)Special Involuntary Termination. In the event of a Special Involuntary Termination, all of the RSUs granted pursuant to this Agreement will become Vested.

(e)Effect of Employment Agreement. Notwithstanding any provision herein to the contrary, in the event of any inconsistency between this Section 6 and any employment, change in control, or similar agreement entered into by and between you and the Company (or any Subsidiary), the terms of the employment, change in control or similar agreement shall control, subject to compliance with Section 409A of the Code.

7.Leave of Absence. With respect to the Award, the Company may, in its sole discretion, determine that if you are on leave of absence for any reason you will be considered to still be in the employ of the Company (or a Subsidiary), provided that rights to the RSUs during a leave of absence will be limited to the extent to which those rights were earned or vested when the leave of absence began.

8.Issuance of Stock. Shares shall be issued to you in settlement of your Vested RSUs within 30 days following the date upon which such RSUs become Vested in accordance with the Agreement. At the time of settlement, the Company shall cause to be issued Shares registered in your name in payment of the Award. The Company shall evidence the Shares to be issued in payment of the RSUs in the manner it deems appropriate. The value of any fractional RSU shall be rounded down at the time Shares are issued to you. No fractional Shares, nor the cash value of any fractional Shares, will be issuable or payable to you pursuant to this Agreement. The value of Shares shall not bear any interest owing to the passage of time. Neither this Section 8 nor any action taken pursuant to or in accordance with this Section 8 shall be construed to create a trust or a funded or secured obligation of any kind.

9.Payment of Taxes. The Company may require you to pay to the Company (or the Company’s Subsidiary if you are an employee of a Subsidiary of the Company), an amount the Company deems necessary to satisfy its (or its Subsidiary’s) current or future withholding with respect to federal, state or local income or other taxes that you incur as a result of the Award. With respect to any tax withholding (and to the extent permissible pursuant to Rule 16b-3 under the Exchange Act, if applicable), you may (a) direct the Company to withhold from the Shares to be issued to you under this Agreement the number of Shares necessary to satisfy the Company’s withholding of such taxes, which determination will be based on the Shares’ Fair Market Value at the time such determination is made; (b) deliver to the Company Shares sufficient to satisfy the Company’s tax withholding, based on the Shares’ Fair Market Value at the time such determination is made; or (c) deliver cash to the Company sufficient to satisfy its tax withholding obligations. If you desire to elect to use the stock withholding option described in subparagraph (a), you must make the election at the time and in the manner the Company prescribes and the maximum number of Shares that may be so withheld or surrendered shall be a number of Shares that have an aggregate Fair Market Value on the date of withholding or repurchase of up to the aggregate amount of such tax liabilities determined based on the greatest withholding rates for you in your relevant federal, state, foreign and/or local tax jurisdiction, including payroll taxes, that may be utilized without creating adverse accounting treatment with respect to the Award. The Company, in its discretion, may deny your request to satisfy its tax withholding obligations using a method described under subparagraph (a) or (b). In the event the Company determines that the aggregate Fair Market Value of the Shares withheld as payment of any tax withholding obligation is insufficient to discharge

that tax withholding obligation, then you must pay to the Company, in cash, the amount of that deficiency immediately upon the Company’s request.

10.Compliance with Securities and Other Applicable Laws. Notwithstanding any provision of this Agreement to the contrary, the issuance of Shares will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Shares may then be listed. No Shares will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other law or regulations or the requirements of any stock exchange or market system upon which the Shares may then be listed. In addition, Shares will not be issued hereunder unless (a) a registration statement under the Securities Act is, at the time of issuance, in effect with respect to the Shares issued or (b) in the opinion of legal counsel to the Company, the Shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any Shares subject to the Award will relieve the Company of any liability in respect of the failure to issue such Shares as to which such requisite authority has not been obtained. As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company. From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate Persons to make Shares available for issuance.

11.Legends. The Company may at any time place legends referencing any restrictions imposed on the Shares pursuant to Sections 4 and 10 of this Agreement on all certificates representing Shares issued with respect to this Award.

12.Right of the Company and Subsidiaries to Terminate Services. Nothing in this Agreement confers upon you the right to continue in the employ of or performing services for the Company or any Subsidiary, or interfere in any way with the rights of the Company or any Subsidiary to terminate your employment or service relationship at any time.

13.Furnish Information. You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

14.Remedies. The Company shall be entitled to recover from you reasonable attorneys’ fees incurred in connection with the successful enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise to the extent allowed by applicable law.

15.No Liability for Good Faith Determinations. The Company and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the RSUs granted hereunder.

16.Execution of Receipts and Releases. Any payment of cash or any issuance or transfer of RSUs or other property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, will, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. In addition, the Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a general release of all claims in favor of the Company, any Affiliate and the employees, officers, stockholders or board members of the foregoing in such form as the Company may determine; provided, however, that any review period under such release will not modify the date of settlement with respect to your Award.

17.Clawback. This Agreement is subject to any written clawback policies that the Company, with the approval of the Board or the Committee, may adopt to the extent allowed by applicable law. Any such policy may subject your RSUs and amounts paid or realized with respect to the RSUs under this Agreement to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted by the Company, including any policy to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to this Agreement.

18.No Guarantee of Interests. Neither the Board nor the Company guarantee the Shares from loss or depreciation.

19.Company Records. Records of the Company or its Subsidiaries regarding your period of employment or service, termination of service and/or employment and the reason(s) therefor, leaves of absence, re-employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.

20.Notice. All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly addressed or, if earlier, the date it is sent via certified United States mail.

21.Waiver of Notice. Any person entitled to notice hereunder may waive such notice in writing.

22.Information Confidential. As partial consideration for the granting of the Award hereunder, you hereby agree to keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required by law and may be given in confidence to your spouse and tax and financial advisors. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor weighing against the advisability of granting any such future award to you. Nothing in this Agreement will prevent you from: (a) making a good faith report of possible violations of applicable

law to any governmental agency or entity or (b) making disclosures that are protected under the whistleblower provisions of applicable law. For the avoidance of doubt, nothing herein shall prevent you from making a disclosure that: (i) is made (A) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. Further, an individual who files a lawsuit for retaliation by an employer of reporting a suspected violation of law may make disclosures without violating this Section 21 to the attorney of the individual and use such information in the court proceeding.

23.Section 409A. It is intended that the RSUs awarded hereunder shall comply with the requirements of Section 409A of the Code (and any regulations and guidelines issued thereunder), and this Agreement shall be interpreted on a basis consistent with such intent. Payments shall only be made on an event and in a manner permitted by Section 409A of the Code. Each payment under this Agreement is considered a separate payment for purposes of Section 409A of the Code. This Agreement may be amended without your consent in any respect deemed by the Committee to be necessary in order to preserve compliance with Section 409A of the Code. All payments to be made upon a termination of employment under this Agreement may only be made upon a “separation from service” under Section 409A of the Code. In no event may you, directly or indirectly, designate the calendar year of a payment. Notwithstanding anything in this Agreement to the contrary, if you are a “specified employee” under Section 409A of the Code at the time of separation from service and if payment of any amount under this Agreement is required to be delayed for a period of six months after the separation from service pursuant to Section 409A of the Code, payment of such amount shall be delayed as required by Section 409A of the Code, and the accumulated postponed amount shall be paid in a lump sum payment within 10 days after the end of the six-month period. If you die during the postponement period prior to the payment of postponed amount, the accumulated postponed amount shall be paid to the personal representative of your estate within 60 days after the date of your death.

24.Successors. This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.

25.Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

26.Company Action. Any action required of the Company shall be by resolution of the Board or by a person or entity authorized to act by resolution of the Board.

27.Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

28.Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of the State of Texas, without giving any effect to any conflict of law provisions thereof, except to the extent Texas state law is preempted

by federal law. The obligation of the Company to sell and deliver Shares hereunder is subject to applicable laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Shares.

29.Consent to Texas Jurisdiction and Venue. You hereby consent and agree that state courts located in Dallas, Texas and the United States District Court for the Northern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Company arising in connection with the RSUs or this Agreement. In any dispute with the Company, you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.

30.Amendment. This Agreement may be amended the Board or by the Committee at any time (a) if the Board or the Committee determines, in its sole discretion, that amendment is necessary or advisable in light of any addition to or change in any federal or state, tax or securities law or other law or regulation, which change occurs after the Date of Grant and by its terms applies to the Award; or (b) other than in the circumstances described in clause (a) or provided in the Plan, with your consent.

31.The Plan. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.

32.Defined Terms.

(a)“Adverse Change” means (i) a change in the city in which you are required to work regularly, (ii) a substantial increase in travel requirements of employment, (iii) a substantial reduction in duties of the type previously performed by you, or (iv) a significant reduction in your compensation or benefits (other than bonuses and other discretionary items of compensation) that does not apply generally to employees of the Company or its successor.

(b)“Affiliate” has the meaning provided in Rule 12b-2 under the Exchange Act.

(c)“Beneficial Owner” has the meaning provided in Rule 13d-3 under the Exchange Act.

(d)“Cause” means:

(i)An act or acts of dishonesty on your part constituting a felony or serious misdemeanor and resulting or intended to result directly in gain or personal enrichment at the expense of the Company or any Subsidiary;

(ii)Gross or willful and wanton negligence in the performance of your material and substantial duties of employment with the Company and its Subsidiaries; or

(iii)Your conviction of a felony involving moral turpitude.

The existence of Cause shall be determined by the Committee, in its sole and absolute discretion.

(e)“Change in Control” means the occurrence of any of the following after the Date of Grant:

(i)Any Person, other than (A) the Company or any of its Subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company, is or becomes the Beneficial Owner, directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates) representing more than 40% of the combined voting power of the Company’s then outstanding securities, or more than 40% of the then outstanding common stock of the Company, excluding any Person who becomes such a Beneficial Owner in connection with a transaction described in Section 32(e)(iii)(1) below.

(ii)The individuals who as of the Date of Grant constitute the Board and any New Director cease for any reason to constitute a majority of the Board.

(iii)There is consummated a merger or consolidation of the Company or any direct or indirect Subsidiary of the Company with any other corporation, except if:

(1)the merger or consolidation results in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60% of the combined voting power of the voting securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation; or

(2)the merger or consolidation is effected to implement a recapitalization of the Company (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly, or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates other than in connection with the acquisition by the Company or its Affiliates of a business) representing more than 40% of the combined voting power of the Company’s then outstanding securities.

(iv)The stockholders of the Company approve a plan of complete liquidation or dissolution of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity at least 60% of the combined voting power of the voting securities of which is owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.

(f)“New Director” means an individual whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds of the directors then still in office who either were directors at the Date of Grant or whose

election or nomination for election was previously so approved or recommended. However, “New Director” shall not include a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation relating to the election of directors of the Company.

(g)“Person” has the meaning given in section 3(a)(9) of the Exchange Act as modified and used in sections 13(d) and 14(d) of the Exchange Act.

(h)“Retirement” means your termination of employment other than for Cause on or after the date on which you: (i) have achieved ten years of continuous service with the Company, and(ii) are age sixty (60).

(i)“Service Period”means the period of time beginning on the Date of Grant specified in the Notice of Grant and ending on the final vesting date specified in the Notice of Grant.

(j)“Special Involuntary Termination” means the occurrence of (1) or (2) below within 60 days prior to, or at any time after, a Change in Control, where (1) is termination of your employment with the Company (including Subsidiaries of the Company) by the Company (or any Subsidiary) for any reason other than Cause and (2) is your resignation from employment with the Company (including Subsidiaries of the Company) within 90 days after an Adverse Change by the Company (including Subsidiaries of the Company) in the terms of your employment.

[Remainder of page intentionally left blank]

EX-10.59

Exhibit 10.59

HOLLYFRONTIER CORPORATION

NOTICE OF GRANT OF RESTRICTED STOCK UNITS
(Time-Based Vesting)

Pursuant to the terms and conditions of the HollyFrontier Corporation Long-Term Incentive Compensation Plan (the “Plan”), and the associated Restricted Stock Unit Agreement (Time-Based Vesting) which has been made separately available to you (the “Agreement”), you are hereby granted an award to receive the number of Restricted Stock Units (“RSUs”) set forth below, whereby each RSU represents the right to receive one Share, plus rights to certain dividend equivalents described in Section 3 of the Agreement, under the terms and conditions set forth below, in the Agreement, and in the Plan. Capitalized terms used but not defined herein shall have the meanings set forth in the Plan or the Agreement. You may obtain a copy of the Plan and a copy of the prospectus related to the Shares by following the instructions attached as Appendix A. Additionally, you may request a copy of the Plan or the prospectus by contacting Cara Whitesel at Cara.Whitesel@hollyfrontier.com or 214.954.6530.

Grantee:	______________________
Date of Grant:	[●], 20[●] (“Date of Grant”)
Number of Restricted Stock Units:	______________________
Vesting Schedule:	The restrictions on all of the RSUs granted pursuant to the Agreement will expire and the RSUs will vest according to the following schedule (or on the first business day thereafter if the date below falls on a weekend) (each such date, a “Regular Vesting Date”); provided, that (except as otherwise provided in Section 6 of your Agreement) you remain in the employ of the Company or its Subsidiaries continuously from the Date of Grant through such Regular Vesting Dates (as determined under the Agreement).

On Each of the Following Regular Vesting Dates	Cumulative Portion of RSUs that will become Vested
December 15, 2018	One-third
December 15, 2019	One-third
December 15, 2020	One-third

Except as otherwise provided in Section 6 of your Agreement, all RSUs that have not become vested and non-forfeitable pursuant to this Notice will be null and void and forfeited to the Company in the event of your termination by the Company or its Subsidiaries for any reason.

A-1

Exhibit 10.59

The Shares you receive upon settlement will be taxable to you in an amount equal to the closing price of the Shares on the date of settlement. By accepting the RSUs you acknowledge and agree that (a) you are not relying on any written or oral statement or representation by the Company, its affiliates, or any of their respective employees, directors, officers, attorneys or agents (collectively, the “Company Parties”) regarding the tax effects associated with this Notice of Grant of Restricted Stock Units and the Agreement and your receipt, holding and vesting of the RSUs, (b) in accepting the RSUs you are relying on your own judgment and the judgment of the professionals of your choice with whom you have consulted, and (c) a copy of the Agreement and the Plan has been made available to you. By accepting the RSUs you hereby release, acquit and forever discharge the Company Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the tax effects associated with this Notice of Grant of Restricted Stock Unit and the Agreement and your receipt, holding and the vesting of the RSUs.

HollyFrontier Corporation

George J. Damiris, Chief Executive Officer and President

Appendix A

A-2

EX-21.1

EXHIBIT 21.1

HOLLYFRONTIER CORPORATION

SUBSIDIARIES OF REGISTRANT

State or Country of

Name of Entity         Incorporation or Organization    

7037619 Canada Inc.        Canada

Black Eagle LLC        Delaware

Cheyenne Logistics LLC ⁽³⁾    Delaware

Cheyenne Pipeline LLC (joint venture) ⁽³⁾    Texas

El Dorado Logistics LLC ⁽³⁾    Delaware

El Dorado Osage LLC        Delaware

El Dorado Operating LLC    ⁽³⁾    Delaware

El Paso Operating LLC        Delaware

Eagle Consolidation LLC        Delaware

Ethanol Management Company LLC    Delaware

Frontier Aspen LLC (f/k/a HEP Casper SLC LLC) ⁽³⁾    Delaware    

Frontier Pipeline LLC        Delaware

Frontier Refining & Marketing LLC    Delaware    

HEP Cheyenne LLC ⁽³⁾        Delaware

HEP Cheyenne Shortline LLC ⁽³⁾    Delaware

HEP El Dorado LLC ⁽³⁾        Delaware

HEP Fin-Tex/Trust-River, L.P. ⁽³⁾    Texas

HEP Logistics GP, L.L.C ⁽³⁾    Delaware

HEP Logistics Holdings, L.P.    Delaware

HEP Mountain Home, L.L.C. ⁽³⁾    Delaware

HEP Navajo Southern, L.P. ⁽³⁾    Delaware

HEP Pipeline Assets, Limited Partnership ⁽³⁾    Delaware

HEP Pipeline GP, L.L.C. ⁽³⁾    Delaware

HEP Pipeline, L.L.C. ⁽³⁾        Delaware

HEP Refining GP, L.L.C. ⁽³⁾    Delaware

HEP Refining Assets, L.P. ⁽³⁾    Delaware

HEP Refining, L.L.C. ⁽³⁾        Delaware

HEP Tulsa LLC ⁽³⁾        Delaware

HEP UNEV Holdings LLC ⁽³⁾    Delaware

HEP UNEV Pipeline LLC     ⁽³⁾    Delaware

HEP Woods Cross, L.L.C. ⁽³⁾    Delaware

Holly Biofuels LLC        Delaware

Holly Energy Finance Corp. ⁽³⁾    Delaware

Holly Energy Partners, L.P. ^{(2) (3)}    Delaware

Holly Energy Holdings LLC ⁽³⁾    Delaware

Holly Energy Partners – Operating, L.P. ^{(2), (3)}    Delaware

Holly Energy Storage – Lovington LLC ⁽³⁾    Delaware

Holly Logistics Limited LLC    Delaware

Holly Logistic Services, L.L.C.    Delaware

Holly Petroleum, Inc.        Delaware

Holly Realty, LLC        Delaware

Holly Refining Communications, Inc.    Delaware

HollyFrontier Asphalt Company LLC    Delaware

HollyFrontier Cheyenne Refining LLC    Delaware

HollyFrontier Cyprus Limited    Cyprus

HollyFrontier El Dorado Refining LLC    Delaware

HollyFrontier Holdings LLC    Delaware

HollyFrontier Luxembourg Holding Company    Luxembourg

HollyFrontier Navajo Refining LLC    Delaware

HollyFrontier Netherlands B.V.    Netherlands

HollyFrontier Payroll Services, Inc.    Delaware

HollyFrontier Refining & Marketing LLC    Delaware

HollyFrontier Services LLC    Delaware

HollyFrontier Transportation LLC    Delaware

HollyFrontier Tulsa Refining LLC    Delaware

HollyFrontier Woods Cross Refining LLC    Delaware

Hollymarks, LLC        Delaware

HRM Realty, LLC        Delaware

Jia Shi Lubricants Trading (Shanghai) Co. Ltd.    China

Lea Refining Company        Delaware

Lovington-Artesia, L.L.C. ⁽³⁾    Delaware

Navajo Holdings, Inc.        New Mexico

Navajo Pipeline Co., L.P. ⁽¹⁾    Delaware

Navajo Pipeline GP, L.L.C.    Delaware

Navajo Pipeline LP, L.L.C.    Delaware

NWNAL LLC ⁽³⁾        Delaware

Osage Pipe Line Company, LLC (joint venture) ⁽³⁾    Delaware

Petro-Canada America Lubricants Inc.    Delaware

Petro-Canada Europe Lubricants Limited    U.K.

Petro-Canada Lubricants Inc.    Canada

Roadrunner Pipeline, L.L.C. ⁽³⁾    Delaware

Sabine Biofuels II, LLC (joint venture)    Delaware

SLC Pipeline LLC (f/k/a HEP SLC, LLC) ⁽³⁾    Delaware    

UNEV Pipeline, LLC (joint venture) ⁽³⁾    Delaware

Wainoco Resources, Inc.        Delaware

Wainoco Oil and Gas Company    Delaware    

Woods Cross Operating LLC ⁽³⁾    Delaware

(1) Navajo Pipeline Co., L.P. also does business as Navajo Pipeline Co.

(2) Holly Energy Partners, L.P. and Holly Energy Partners – Operating, L.P. also do business as Holly Energy Partners.

(3) Represents a subsidiary of Holly Energy Partners, L.P. We have presented these entities in our list of subsidiaries as a result of our reconsolidation of Holly Energy Partners, L.P. on March 1, 2008.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-8 No. 333-211557) of HollyFrontier Corporation, and

(2) Registration Statement (Form S-3 ASR No. 333-208155) of HollyFrontier Corporation;

of our reports dated February 21, 2018, with respect to the consolidated financial statements of HollyFrontier Corporation and the effectiveness of internal control over financial reporting of HollyFrontier Corporation included in this Annual Report (Form 10-K) for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Dallas, Texas

February 21, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION

I, George J. Damiris, certify that:

1. I have reviewed this annual report on Form 10-K of HollyFrontier Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting

Date: February 21, 2018	/s/ George J. Damiris
	George J. Damiris
	Chief Executive Officer and President

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard L. Voliva III, certify that:

1. I have reviewed this annual report on Form 10-K of HollyFrontier Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's most recent fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2018	/s/ Richard L. Voliva III
	Richard L. Voliva III
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE

OFFICER UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the accompanying report on Form 10-K for the period ending December 31, 2017 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George J. Damaris, Chief Executive Officer of HollyFrontier Corporation (the “Company”) hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 21, 2018	/s/ George J. Damiris
	George J. Damiris
	Chief Executive Officer and President

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL

OFFICER UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the accompanying report on Form 10-K for the period ending December 31, 2017 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas S. Aron, Chief Financial Officer of HollyFrontier Corporation (the “Company”) hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 21, 2018	/s/ Richard L. Voliva III
	Richard L. Voliva III
	Executive Vice President and Chief Financial Officer

XML

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	HollyFrontier Corp
Entity Central Index Key	0000048039
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		177,363,228
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 4.5

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents (HEP: $7,776 and $3,657, respectively)	$ 630,757	$ 710,579
Marketable securities	0	424,148
Total cash, cash equivalents and short-term marketable securities	630,757	1,134,727
Accounts receivable: Product and transportation (HEP: $12,803 and $7,846, respectively)	659,530	449,036
Crude oil resales	61,203	30,163
Accounts receivable, total	720,733	479,199
Crude oil and refined products	1,409,538	970,361
Materials, supplies and other (HEP: $916 and $1,402, respectively)	220,554	165,315
Total inventory	1,630,092	1,135,676
Income taxes receivable	44,337	68,371
Prepayments and other (HEP: $1,395 and $1,486, respectively)	36,909	33,036
Total current assets	3,062,828	2,851,009
Properties, plants and equipment, at cost (HEP: $2,009,960 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)
Property, plant and equipment, net	4,713,274	4,008,448
Other assets: Turnaround costs	231,319	217,340
Goodwill (HEP: $296,164 and $288,991, respectively)	2,244,744	2,022,463
Intangibles and other (HEP: $220,068 and $208,975, respectively)	439,989	336,401
Other assets, total	2,916,052	2,576,204
Total assets	10,692,154	9,435,661
Current liabilities:
Accounts payable (HEP: $14,637 and $10,518, respectively)	1,220,795	935,387
Income taxes payable	3,159	0
Accrued liabilities (HEP: $33,214 and $37,793, respectively)	198,756	147,842
Total current liabilities	1,422,710	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
HollyFrontier stockholders’ equity:
Preferred stock, $1.00 par value – 5,000,000 shares authorized; none issued	0	0
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, 2016	2,560	2,560
Additional capital	4,132,696	4,026,805
Retained earnings	3,346,615	2,776,728
Accumulated other comprehensive income (loss)	29,869	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’ equity	5,370,829	4,681,394
Noncontrolling interest	526,111	620,591
Total equity	5,896,940	5,301,985
Total liabilities and equity	10,692,154	9,435,661
HEP
Current assets:
Cash and cash equivalents (HEP: $7,776 and $3,657, respectively)	7,776	3,657
Accounts receivable: Product and transportation (HEP: $12,803 and $7,846, respectively)	12,803	7,846
Materials, supplies and other (HEP: $916 and $1,402, respectively)	916	1,402
Prepayments and other (HEP: $1,395 and $1,486, respectively)	1,395	1,486
Properties, plants and equipment, at cost (HEP: $2,009,960 and $1,702,703, respectively)	2,011,915	1,702,703
Less accumulated depreciation (HEP: ($408,599) and ($337,135), respectively)	(408,599)	(337,135)
Goodwill (HEP: $296,164 and $288,991, respectively)	310,610	288,991
Intangibles and other (HEP: $220,068 and $208,975, respectively)	206,167	208,975
Current liabilities:
Accounts payable (HEP: $14,637 and $10,518, respectively)	14,637	10,518
Accrued liabilities (HEP: $33,214 and $37,793, respectively)	33,214	37,793
Deferred income taxes (HEP: $525 and $509, respectively)	525	509
Other long-term liabilities (HEP: $62,590 and $62,971, respectively)	$ 62,590	$ 62,971

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Cash and cash equivalents (HEP: $7,776 and $3,657, respectively)	$ 630,757	$ 710,579
Accounts receivable: Product and transportation (HEP: $12,803 and $7,846, respectively)	659,530	449,036
Materials, supplies and other (HEP: $916 and $1,402, respectively)	220,554	165,315
Prepayments and other (HEP: $1,395 and $1,486, respectively)	36,909	33,036
Properties, plants and equipment, at cost (HEP: $2,009,960 and $1,702,703, respectively)	6,523,789	5,546,856
Accumulated depreciation	(1,810,515)	(1,538,408)
Goodwill (HEP: $296,164 and $288,991, respectively)	2,244,744	2,022,463
Intangibles and other	439,989	336,401
Accounts payable (HEP: $14,637 and $10,518, respectively)	1,220,795	935,387
Accrued liabilities (HEP: $33,214 and $37,793, respectively)	198,756	147,842
Long-term Debt and Capital Lease Obligations	2,498,993	2,235,137
Deferred income tax liabilities	647,785	620,414
Other long-term liabilities (HEP: $62,590 and $62,971, respectively)	$ 225,726	$ 194,896
HollyFrontier Stockholders' Equity:
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	320,000,000	320,000,000
Common stock, shares issued	256,015,550	255,962,866
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Treasury stock, shares	78,607,928	78,617,600
HEP
Cash and cash equivalents (HEP: $7,776 and $3,657, respectively)	$ 7,776	$ 3,657
Accounts receivable: Product and transportation (HEP: $12,803 and $7,846, respectively)	12,803	7,846
Materials, supplies and other (HEP: $916 and $1,402, respectively)	916	1,402
Prepayments and other (HEP: $1,395 and $1,486, respectively)	1,395	1,486
Properties, plants and equipment, at cost (HEP: $2,009,960 and $1,702,703, respectively)	2,011,915	1,702,703
Accumulated depreciation	(408,599)	(337,135)
Goodwill (HEP: $296,164 and $288,991, respectively)	310,610	288,991
Intangibles and other	206,167	208,975
Accounts payable (HEP: $14,637 and $10,518, respectively)	14,637	10,518
Accrued liabilities (HEP: $33,214 and $37,793, respectively)	33,214	37,793
Long-term Debt and Capital Lease Obligations	1,507,308	1,243,912
Deferred income tax liabilities	525	509
Other long-term liabilities (HEP: $62,590 and $62,971, respectively)	$ 62,590	$ 62,971

XML

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Sales and other revenues	$ 14,251,299	$ 10,535,700	$ 13,237,920
Operating costs and expenses:
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
Cost of products sold (exclusive of depreciation and amortization)	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	0
Total operating costs and expenses	13,347,406	10,635,587	11,993,567
Income 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)	0
Gain on foreign currency transactions	16,921	0	0
Remeasurement gain on pipeline interest acquisition	36,254
Remeasurement gain on pipeline interest acquisition	(36,254)	0	0
Other, net	826	(921)	9,402
Other income (expense) total	(35,030)	71,647	35,785
Income (loss) before income taxes	868,863	(171,534)	1,208,568
Income tax provision:
Current	125,143	(79,181)	552,196
Deferred	(137,522)	98,592	(146,136)
Income tax provision total	(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

XML

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 881,242	$ (190,945)	$ 802,508
Other comprehensive income (loss):
Foreign currency translation adjustment	22,151	0	0
Unrealized gain (loss) on marketable securities	(4)	81	29
Reclassification adjustment to net income on sale or maturity of marketable securities	0	23	9
Net unrealized gain (loss) on marketable securities	(4)	104	38
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)
Unrealized loss on pension liability	(1,162)	0	0
Unrealized gain (loss) on post-retirement healthcare plans	(1,058)	2,363	3,278
Post-retirement healthcare plan loss reclassified to net income	(3,481)	(3,482)	(3,299)
Unrealized gain (loss) on retirement restoration plan	(123)	(9)	80
Retirement restoration 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

XML

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 881,242,000	$ (190,945,000)	$ 802,508,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	409,937,000	363,027,000	346,151,000
Goodwill and asset impairment	19,247,000	654,084,000	0
Lower of cost or market inventory valuation adjustment	(108,685,000)	(291,938,000)	226,979,000
Earnings of equity method investments, inclusive of distributions	1,450,000	961,000	8,613,000
(Gain) loss on early extinguishment of debt	2,475,000	8,718,000	(3,788,000)
Remeasurement gain on pipeline interest acquisition	(36,254,000)	0	0
Loss (gain) on sale of assets	508,000	(72,000)	(8,677,000)
Deferred income taxes	(137,522,000)	98,592,000	(146,136,000)
Equity-based compensation expense	42,337,000	25,561,000	30,367,000
Change in fair value – derivative instruments	(4,265,000)	(12,155,000)	38,525,000
Proceeds and Excess Tax Benefit from Share-based Compensation	0	(4,209,000)	0
(Increase) decrease in current assets:
Accounts receivable	(115,322,000)	(127,221,000)	238,392,000
Inventories	(162,297,000)	(1,869,000)	(33,717,000)
Income taxes receivable	50,601,000	(68,371,000)	11,719,000
Prepayments and other	(6,753,000)	16,555,000	13,291,000
Increase (decrease) in current liabilities:
Accounts payable	188,975,000	247,603,000	(406,339,000)
Income taxes payable	(18,525,000)	(8,142,000)	(11,500,000)
Accrued liabilities	57,227,000	16,142,000	(6,924,000)
Turnaround expenditures	(135,104,000)	(125,254,000)	(89,365,000)
Other, net	22,118,000	5,881,000	(24,231,000)
Net cash provided by operating activities	951,390,000	606,948,000	985,868,000
Cash flows from investing activities:
Additions to properties, plants and equipment	(227,449,000)	(372,195,000)	(483,034,000)
Purchase of PCLI, net of cash acquired	(870,627,000)	0	0
Proceeds from sale of assets	1,377,000	849,000	19,264,000
Purchases of marketable securities	(41,565,000)	(546,632,000)	(509,338,000)
Sales and maturities of marketable securities	465,716,000	266,603,000	839,513,000
Other, net	3,134,000	0	0
Net cash used for investing activities	(959,670,000)	(801,597,000)	(381,748,000)
Cash flows from financing activities:
Proceeds from issuance of senior notes	0	992,550,000	0
Net proceeds from issuance of term loan - HFC	0	350,000,000	0
Repayment of term loan	0	(350,000,000)	0
Redemption of senior notes - HFC	0	0	(155,156,000)
Repayment of financing obligation	0	(39,500,000)	0
Proceeds from issuance of common units - HEP	52,110,000	125,870,000	0
Purchase of treasury stock	0	(133,430,000)	(742,823,000)
Shares withheld for tax withholding obligations	(15,926,000)	(4,677,000)	(6,242,000)
Dividends	(235,508,000)	(234,004,000)	(246,908,000)
Distributions to noncontrolling interest	(110,351,000)	(92,607,000)	(83,268,000)
Other, net	(13,955,000)	(10,507,000)	(12,175,000)
Net cash used for financing activities	(72,630,000)	838,695,000	(1,105,572,000)
Effect of exchange rate on cash flow	1,088,000	0	0
Cash and cash equivalents:
Increase (decrease) for the period	(79,822,000)	644,046,000	(501,452,000)
Beginning of period	710,579,000	66,533,000	567,985,000
End of period	630,757,000	710,579,000	66,533,000
Cash (paid) received during the period for:
Interest	(124,375,000)	(54,074,000)	(46,442,000)
Income taxes, net	(93,272,000)	(40,236,000)	(586,447,000)
HEP
Cash flows from investing activities:
Additions to properties, plants and equipment	(44,810,000)	(107,595,000)	(193,121,000)
Purchase of pipeline interests - HEP	(245,446,000)	(42,627,000)	(55,032,000)
Cash flows from financing activities:
Borrowings under credit agreement	995,000,000	869,000,000	973,900,000
Repayments under credit agreement	(536,000,000)	(1,028,000,000)	(832,900,000)
Proceeds from issuance of senior notes	101,750,000	394,000,000	0
Redemption of senior notes - HEP	(309,750,000)	0	$ 0
Cash and cash equivalents:
Beginning of period	3,657,000
End of period	$ 7,776,000	$ 3,657,000

XML

Consolidated Statements Of Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Non-controlling Interest
Beginning Balance at Dec. 31, 2014	$ 6,100,719	$ 2,560	$ 4,003,628	$ 2,778,577	$ 27,894	$ (1,289,075)	$ 577,135
Net income (loss)	802,508			740,101			62,407
Dividends	(247,489)			(247,489)
Distributions to noncontrolling interest holders	(83,268)						(83,268)
Other comprehensive income (loss), net of tax	(31,905)				(32,049)	0	144
Issuance of common stock under incentive compensation plans, net of forfeitures			(14,958)			14,958
Equity-based compensation, inclusive of tax expense	25,865		22,382				3,483
Purchase of treasury stock	(753,114)					(753,114)	0
Purchase of HEP units for restricted grants	(3,555)						(3,555)
Other	12						12
Ending Balance at Dec. 31, 2015	5,809,773	2,560	4,011,052	3,271,189	(4,155)	(2,027,231)	556,358
Net income (loss)	(190,945)			(260,453)			69,508
Dividends	(234,008)			(234,008)
Distributions to noncontrolling interest holders	(92,607)						(92,607)
Other comprehensive income (loss), net of tax	14,709				14,767	0	(58)
Equity attributable to HEP common unit issuances, net of tax	111,276		23,110				88,166
Issuance of common stock under incentive compensation plans, net of forfeitures			(25,982)			25,982
Equity-based compensation, inclusive of tax expense	21,352		18,625				2,727
Purchase of treasury stock	(134,062)					(134,062)	0
Purchase of HEP units for restricted grants	(3,521)						(3,521)
Other	18						18
Ending Balance at Dec. 31, 2016	5,301,985	2,560	4,026,805	2,776,728	10,612	(2,135,311)	620,591
Net income (loss)	881,242			805,395			75,847
Dividends	(235,508)			(235,508)
Distributions to noncontrolling interest holders	(110,351)						(110,351)
Other comprehensive income (loss), net of tax	19,438				19,495	0	(57)
Equity attributable to HEP common unit issuances, net of tax	8,174		69,802		(238)		(61,390)
Equity awards issued on PCLI acquisition	6,600		(6,600)				0
Issuance of common stock under incentive compensation plans, net of forfeitures			(10,326)			10,326
Equity-based compensation, inclusive of tax expense	42,337		39,815				2,522
Purchase of treasury stock	(15,926)					(15,926)	0
Purchase of HEP units for restricted grants	(605)						(605)
Other	(446)						(446)
Ending Balance at Dec. 31, 2017	$ 5,896,940	$ 2,560	$ 4,132,696	$ 3,346,615	$ 29,869	$ (2,140,911)	$ 526,111

XML

Description of Business and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Summary of Significant Accounting Policies

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 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 regions of the United States. In addition, we own and operate a lubricant production facility with retail and wholesale marketing of its products through a global sales network with locations in Canada, United States, Europe and China. As of December 31, 2017, 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 and operated Petro-Canada Lubricants Inc. (“PCLI”) located in Mississauga, Ontario which produces base oils and other specialized lubricant products;

• owned and operated HollyFrontier Asphalt Company (“HFC Asphalt”) which operates various asphalt terminals in Arizona, New Mexico and Oklahoma; and

• owned a 59% limited partner interest and a non-economic general partner interest in HEP, a variable interest entity (“VIE”).

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of PCLI. The acquisition closed on February 1, 2017. See Note 2 for additional information.

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.

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.

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 because it more appropriately presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated with such assets and liabilities.

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. 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 million at December 31, 2017 and 2016, respectively.

Accounts receivable attributable to crude oil resales generally represent the sell side 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'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 business 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 RINs are stated at the lower of weighted-average cost or net realizable value.

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 13 for additional information.

Properties, plants and 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.

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 million and $22.1 million at December 31, 2017 and 2016, 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, 2016 and 2015.

Intangibles, Goodwill and 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 not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our goodwill impairment testing first entails a comparison of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting unit, we measure goodwill impairment as the excess of 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 the reporting unit.

Our long-lived assets principally consist of our refining assets that are organized as refining asset groups and our lubricants and specialty products business. The refinery asset groups also constitute our individual refinery reporting units that are used for testing and measuring goodwill impairments. 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 10 for information regarding goodwill and long-lived asset impairment charges recorded during the years ended December 31, 2017 and 2016.

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: 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 accounting for investments in which we have a noncontrolling interest, yet have significant influence over the entity. Under the equity method of accounting, 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 for using the equity method of accounting. As of December 31, 2017, HEP's underlying equity and recorded investment balances in the joint ventures are $39.3 million and $85.3 million, respectively. The differences are being amortized as adjustments to HEP's pro-rata share of earnings in the joint ventures.

Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines. 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 in cost of products sold.

Our Petro-Canada Lubricants 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, and for sales to U.S. distributors, revenues are recognized when products are shipped to the distributors, net of allowances for returns that are expected to be repurchased from the distributors. In both cases, repurchased products are subsequently sold directly to end customers.

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 million, $110.6 million and $107.8 million for the years ended December 31, 2017, 2016 and 2015, 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. 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.

Foreign Currency Translation: The functional currency of PCLI and its affiliated non-U.S. Petro-Canada Lubricants entities includes the Canadian dollar, the euro and Chinese renminbi. Balance sheet accounts 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 corporate and other. See Note 20 for additional information on our segments.

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 obligation that is subsequently reversed when the inventory is repurchased. For the years ended December 31,2017, 2016 and 2015, we received proceeds of $47.4 million, $57.0 million and $115.4 million and subsequently repaid $49.8 million, $58.0 million and $115.3 million, respectively, under these sell / buy transactions.

New Accounting Pronouncements

Hedge Accounting

In August 2017, Accounting Standard Update (“ASU”) 2017-12, “Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities,” was issued amending hedge accounting recognition and presentation requirements, including elimination of the requirement to separately measure and report hedge ineffectiveness, and eases certain documentation and assessment requirements. This standard has an effective date of January 1, 2019. We do not expect adoption of this standard to have a material impact on our financial condition, results of operations or cash flows.

Post-retirement Benefit Cost

In March 2017, ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost,” was issued amending 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, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017 on a prospective basis with the excess tax expense from stock-based compensation recognized as a discrete item in our provision for income taxes. Excess tax expense for the year ended December 31, 2017 totaled $0.7 million. The new standard also requires that employee taxes paid when an employer withholds shares 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 leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. 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.

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.

XML

Acquisition

12 Months Ended

Dec. 31, 2017

Schedule of assets purchased and liabilities assumed in acquisition [Abstract]

PCLI Acquisition

PCLI Acquisition

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor to acquire 100% 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. PCLI is located in Mississauga, Ontario, Canada and is a producer of lubricant products such as base oils, white oils, specialty products 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 network with locations in Canada, the United States, Europe and China.

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 is accounted for as a business combination using the acquisition method of accounting, with the purchase price allocated to the fair value of the acquired PCLI assets and liabilities as of the February 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.

The following summarizes the PCLI value of assets and liabilities acquired on February 1, 2017:

	(in millions)
Cash and cash equivalents	$	21.6
Accounts receivable and other current assets	118.5
Inventories	214.9
Properties, plants and equipment	438.0
Goodwill	194.8
Intangibles, precious metals and other noncurrent assets	124.3
Accounts payable and accrued liabilities	(87.4		)
Deferred income tax liabilities	(105.4		)
Other long-term liabilities	(12.6		)
Net assets acquired	$	906.7

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

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

XML

Holly Energy Partners

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Holly Energy Partners

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 in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Delek’s refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), the owner of 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 the Osage Pipeline and the Cheyenne Pipeline.

At December 31, 2017, we owned a 59% 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 two 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 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% of HEP’s total revenues for the year ended December 31, 2017. 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 12 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 Pipeline

On October 31, 2017, HEP acquired the remaining 75% interest in SLC Pipeline LLC, the owner of 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 subsidiaries of Plains All American Pipeline, L.P. (“Plains”) for cash consideration of $250.0 million.

These acquisitions were accounted for as a business combination achieved in stages. HEP’s preexisting equity method investments 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 investments 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 million and the fair value of HEP's preexisting equity method investments 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 in the second quarter of 2016, for cash consideration of approximately $278.0 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 $56.7 million.

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. Cheyenne Pipeline will continue to be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie, 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. Previously in 2009, we sold these tanks to 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 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. 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.

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 through 2036. Under 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, these agreements result in minimum annualized payments to HEP of $324.5 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.

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

On 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, HEP issued 1,538,452 common units under this program, providing $52.1 million in net 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.

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Financial Instruments, Owned, at Fair Value [Abstract]

Fair Value Measurements

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.

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 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, derivative instruments consisting of 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 values of the commodity price and interest rate swap contracts are 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, quoted forward commodity prices with respect to our commodity price swaps and the forward London Interbank Offered Rate (“LIBOR”) yield curve with respect to HEP's interest rate swaps. RINs credit obligations are valued based on current market RINs prices. The fair value of the marketable securities is based on values provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input.

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	)

XML

Earnings Per Share

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share is calculated as net income (loss) attributable to HollyFrontier stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares from restricted shares and performance share units. 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,
	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 andperformance 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

XML

Stock-Based Compensation

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Stock-Based Compensation

Stock-Based Compensation

As of December 31, 2017, we have two principal share-based compensation plans (collectively, the “Long-Term Incentive Compensation Plan”).

The compensation cost charged against income for these plans was $39.8 million, $22.8 million and $26.9 million for the years ended December 31, 2017, 2016 and 2015, 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 million, $2.7 million and $3.5 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Restricted Stock and Restricted Stock Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees restricted stock unit awards with awards generally vesting over a period of two to three years. We previously granted restricted stock to certain officers and key employees with awards vesting over a period of three years. Certain restricted 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 share units lapse at which time they convert to common shares. 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.

A summary of restricted stock and restricted stock unit activity and changes during the year ended December 31, 2017 is presented below:

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, 2016 and 2015, restricted stock and restricted stock units vested having a grant date fair value of $24.9 million, $18.4 million and $14.2 million, respectively. For the years ended December 31, 2016 and 2015, we granted restricted stock and restricted stock units having a weighted average grant date fair value of $21.66 and $49.92, respectively. As of December 31, 2017, there was $33.9 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 1.6 years.

Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in stock 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 under these awards can range from zero to 200% of target award amounts. As of December 31, 2017, estimated share payouts for outstanding non-vested performance share unit awards averaged approximately 110% of target amounts.

A summary of performance share unit activity and changes during the year ended December 31, 2017 is presented below:

Performance Share Units	Grants
Outstanding at January 1, 2017 (non-vested)	703,939
Granted	239,964
Vesting and transfer of ownership to recipients	(151,599	)
Forfeited	(99,643	)
Outstanding at December 31, 2017 (non-vested)	692,661

For the year ended December 31, 2017, we issued 138,374 shares of common stock, representing a 91% payout on vested performance share units having a grant date fair value of $6.6 million. For the years ended December 31, 2016 and 2015, we issued common stock upon the vesting of the performance share units having a grant date fair value of $7.4 million and $10.4 million, respectively. As of December 31, 2017, there was $15.6 million of total unrecognized compensation cost related to non-vested performance share units having a grant date fair value of $33.94 per unit. That cost is expected to be recognized over a weighted-average period of 2.1 years.

XML

Cash and Cash Equivalents and Investments in Marketable Securities

12 Months Ended

Dec. 31, 2017

Cash, Cash Equivalents, and Short-term Investments [Abstract]

Cash and Cash Equivalents and Investments in Marketable Securities

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:

	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.

XML

Inventories

12 Months Ended

Dec. 31, 2017

Inventory, Net [Abstract]

Inventories

Inventories

Inventory consists of the following components:

	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) 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, unfinished and finished products and repair and maintenance supplies in connection with our February 1, 2017 acquisition of PCLI. We value these inventories at the lower of FIFO cost or net realizable value.

Inventories which are valued at the lower of LIFO cost or market reflect a valuation reserve of $223.8 million and $332.5 million at December 31, 2017 and 2016, respectively. The December 31, 2016 market reserve of $332.5 million was reversed due to the sale of inventory quantities that gave rise to the 2016 reserve. A new market reserve of $223.8 million was established as of December 31, 2017 based on market conditions and prices at that time. The effect of the change in the lower of cost or market reserve was a decrease to cost of goods sold of $108.7 million and $291.9 million for the years ended December 31, 2017 and 2016, respectively, and an increase of $227.0 million for the year ended December 31, 2015.

At December 31, 2017, 2016 and 2015, the LIFO value of inventory, net of the lower of cost or market reserve, was equal to current costs.

In May 2017, the EPA granted the Cheyenne Refinery a one-year small refinery exemption from the Renewable Fuel Standard (“RFS”) program requirements for the 2016 calendar year. As a result, the Cheyenne 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. In the second quarter of 2017, we increased our inventory of RINs and reduced our cost of products sold by this amount, representing the cost of the RINs that were reinstated as a result of the RFS exemption received by the Cheyenne Refinery.

Additionally, in December 2017, the EPA granted the Woods Cross Refinery a one-year small refinery exemption from the RFS program requirements for the 2016 calendar year. In the fourth quarter of 2017, we increased our inventory of RINs and reduced our cost of products sold in the amount of $27.3 million, representing the cost of the RINs to be reinstated as a result of the RFS exemption received by the Woods Cross Refinery. These RINs were reinstated in January 2018.

XML

Properties, Plants and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Properties, Plants and Equipment

Properties, Plants and Equipment

The components of properties, plants and equipment are as follows:

	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 million, $8.0 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Depreciation expense was $286.5 million, $247.9 million and $233.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.

XML

Goodwill and Long-lived Asset Impairment

12 Months Ended

Dec. 31, 2017

Goodwill [Abstract]

Goodwill and Long-lived Asset Impairment

Goodwill and Long-lived Asset Impairment

As of December 31, 2017, our goodwill balance was $2.2 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.

The following is a summary of our goodwill by segment:

	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

We performed our annual goodwill 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, we incurred long-lived asset impairment charges totaling $23.2 million, including $19.2 million of construction-in-progress consisting primarily of engineering work for a planned expansion of our Woods Cross refinery to add lubricants production capabilities. During the second quarter of 2017, we concluded to no longer pursue this expansion for various reasons including 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, as a result of our impairment testing in the second quarter of 2016, we determined that the carrying value of the long-lived assets of the Cheyenne Refinery had been impaired and recorded long-lived asset impairment charges of $344.8 million that principally related to properties, plant and equipment.

During the second quarter of 2016, we performed interim goodwill impairment and related long-lived asset impairment testing of our El Dorado and Cheyenne Refinery reporting units after identifying a combination of events and circumstances that are indicators

of potential goodwill and long-lived asset impairment. The indicators included lower than typical gross margins during the summer driving season, a decrease in the gross margin outlook and decrease in our market capitalization due to a decline in our common share price. Our testing first assessed the carrying values of our refining long-lived asset groups for recoverability. This entailed a comparison of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting unit, we measure goodwill impairment as the excess of 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 the reporting unit. The estimated fair values of our goodwill reporting units and long-lived asset groups 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, forecasted production levels, 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-kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs). As a result of our impairment testing during the second quarter of 2016, we determined that the carrying value of the Cheyenne Refinery’s goodwill was fully impaired and a goodwill impairment charge of $309.3 million was recorded, representing all of the goodwill allocated to our Cheyenne Refinery. Our interim testing in 2016 did not identify any 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.

XML

Environmental

12 Months Ended

Dec. 31, 2017

Environmental Expense and Liabilities [Abstract]

Environmental

Environmental

We expensed $13.1 million, $6.6 million and $14.7 million for the years ended December 31, 2017, 2016 and 2015, respectively, for environmental remediation obligations. The accrued environmental liability reflected in our consolidated balance sheets was $103.7 million and $96.4 million at December 31, 2017 and 2016, respectively, of which $89.6 million and $82.9 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.

XML

Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt

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 ended December 31, 2017, we received advances totaling $26.0 million and repaid $26.0 million under the HollyFrontier Credit Agreement. At December 31, 2017, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $2.8 million under the HollyFrontier Credit Agreement.

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, HEP received advances totaling $969.0 million and repaid $510.0 million under the HEP Credit Agreement. At December 31, 2017, HEP was in compliance with all of its covenants, had outstanding borrowings of $1,012.0 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% and 2.98% at December 31, 2017 and 2016, 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 2016 and November 2016, we issued $250 million and $750 million, respectively, in aggregate principal amount of 5.875% senior notes (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.

In June 2015, we redeemed our $150.0 million aggregate principal amount of 6.875% senior notes maturing November 2018 at a redemption cost of $155.2 million at which time we recognized a $1.4 million early extinguishment loss consisting of a $5.2 million debt redemption premium, net of an unamortized premium of $3.8 million.

HollyFrontier Financing Obligation

In March 2016, we extinguished a financing obligation at a cost of $39.5 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 repaid with proceeds received upon the November 2016 issuance of the HollyFrontier Senior Notes.

HEP Senior Notes

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

HEP's 6.0% senior notes ($500 million aggregate principal amount maturing August 2024) (the “HEP Senior 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. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and 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,
	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,
	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 4 for additional information on Level 2 inputs.

Principal maturities of long-term debt are as follows:

Years Ending December 31,	(In thousands)
2018	$	—
2019	—
2020	—
2021	—
2022	1,012,000
Thereafter	1,500,000
Total	$	2,512,000

XML

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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:

• our inventory positions;

• natural gas purchases;

• costs of crude oil and related grade differentials;

• prices of refined products; and

• our refining margins.

Accounting Hedges

We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas. We also periodically have 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.

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 sales under hedge accounting:

	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 and NYMEX futures contracts to lock in prices on forecasted purchases of inventory. In addition, we periodically have swap contracts that serve as economic hedges (derivatives used for risk management, but not designated as accounting hedges) to lock in basis spread differentials on forecasted purchases 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), which were settled on February 1, 2017, in connection with the closing of the PCLI acquisition. These contracts are measured at fair value with offsetting adjustments (gains/losses) recorded directly to income.

The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges:

	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, we have the following notional contract volumes related to our outstanding derivative contracts serving as economic hedges (all maturing in 2018):

Derivative Instrument	Total Outstanding Notional	Unit of Measure
NYMEX futures (WTI) - short	1,175,000	Barrels
Forward gasoline and diesel contracts - long	85,000	Barrels

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:

	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	)

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 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 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

At December 31, 2017, we had a pre-tax net unrealized loss of $1.3 million classified in accumulated other comprehensive income that relates to all accounting hedges having contractual maturities through 2021. 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.

XML

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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.

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.

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,
	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

The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense (benefit) as follows:

	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, 2017 and 2016 are as follows:

	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, 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	)

We have Oklahoma income tax credits of $9.7 million that can be carried forward indefinitely, and Kansas income tax credits of $16.8 million that can be carried forward for 16 tax years.

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

	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, 2017 and 2016, there were $53.8 million and $22.1 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 to 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 believe it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase within 12 months of the reporting date based on additional filings.

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. 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.

XML

Stockholders' Equity

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Note [Abstract]

Stockholders' Equity

Stockholders' Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2017, 2016 and 2015 are presented below:

	Years Ended December 31,
	2017		2016		2015
Common shares outstanding at January 1	177,345,266		180,234,388		196,086,090
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 restricted stock with performance feature	350,063		40,294		43,774
Forfeitures of restricted stock	(139,634	)	(16,795	)	(51,332	)
Purchase of treasury stock (1)	(342,073	)	(3,859,403	)	(16,428,574	)
Common shares outstanding at December 31	177,407,622		177,345,266		180,234,388

(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.

In May 2015, our Board of Directors approved a $1 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, we had remaining authorization to repurchase up to $178.8 million 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, 2016 and 2015, we withheld shares of our common stock from certain employees in the amounts of $15.9 million, $4.7 million and $6.2 million, respectively. These withholdings were made under the terms of restricted stock 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.

XML

Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2017

Other Comprehensive Income (Loss), before Tax [Abstract]

Other Comprehensive Income (Loss)

Other Comprehensive Income (Loss)

The components and allocated tax effects of other comprehensive income are as follows:

	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	)

The following table presents the income statement line item effects for reclassifications out of accumulated other comprehensive income (“AOCI”):

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,
	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

XML

Post-retirement Plans

12 Months Ended

Dec. 31, 2017

Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]

Post-retirement Plans

Post-retirement Plans

In connection with our PCLI acquisition, we agreed to establish employee benefit plans including union and non-union pension plans and a post-retirement healthcare plan for PCLI employees that were previously covered under legacy Suncor plans.

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 months ended December 31, 2017:

	February 1, 2017 to December 31, 2017
	(In thousands)
Change in plans' benefit obligations
Pension plans' benefit obligation at acquisition	$	52,155
Service cost	3,598
Interest cost	1,979
Actuarial loss	4,503
Benefits paid	(966		)
Foreign currency exchange rate changes	2,313
Pension plans' benefit obligation - end of year	$	63,582
Change in pension plans assets
Fair value of plans assets at acquisition	$	51,870
Actual return on plans assets	6,182
Benefits paid	(966		)
Foreign currency exchange rate changes	2,175
Fair value of plans assets - end of year	$	59,261
Funded status
Under-funded balance	$	(4,321	)
Amounts recognized in consolidated balance sheets
Accrued pension liability	$	(4,321	)
Amounts recognized in accumulated other comprehensive income
Cumulative actuarial loss	$	1,162

The accumulated benefit obligation was $52.8 million at December 31, 2017. The measurement date used for our pension plans was December 31, 2017.

The weighted average assumptions used to determine end of period benefit obligations:

	December 31, 2017
Discount rate	3.40	%
Rate of future compensation increases	3.00	%

Net periodic pension expense consisted of the following components:

	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

The weighted average assumptions used to determine net periodic pension expense:

	February 1, 2017 to December 31, 2017
Discount rate	3.80	%
Rate of future compensation increases	3.00	%
Expected long-term rate of return on assets	5.75	%

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 million in 2021, $2.1 million in 2022 and $14.9 million in 2023 to 2027.

Post-retirement Healthcare Plans

We have a post-retirement healthcare and other benefits plan that is available to certain of our employees who satisfy certain age and service requirements. This plan is unfunded and provides 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.

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, 2017 and 2016:

	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

Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.9 million in 2018; $1.6 million in 2019; $1.6 million in 2020; $1.7 million in 2021; $1.7 million in 2022; and $8.2 million in 2023 through 2027.

The weighted average assumptions used to determine end of period benefit obligations:

	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

Net periodic post-retirement credit consisted of the following components:

	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	)

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	)

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 million, $0.1 million and $0.1 million for the years ended December 31, 2017, 2016 and 2015, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $2.7 million and $2.7 million at December 31, 2017 and 2016, respectively. As of December 31, 2017, the projected benefit obligation under this plan was $2.7 million. Annual benefit payments of $0.2 million are expected to be paid through 2027, which reflect expected future service.

Defined Contribution Plan

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

XML

Lease Commitments

12 Months Ended

Dec. 31, 2017

Leases, Operating [Abstract]

Lease Commitments

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 million for the years ended December 31, 2017, 2016 and 2015, respectively.

XML

Contingencies And Contractual Commitments

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Contingencies And Contractual Commitments

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.

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 2019 through 2033.

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 2018 through 2033. At December 31, 2017, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:

	(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 million, $135.1 million and $137.7 million for the years ended December 31, 2017, 2016 and 2015, 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.

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.

XML

Segment Information

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information

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 three reportable 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 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 regions of the United States. HFC Asphalt operates various asphalt terminals in Arizona, New Mexico and Oklahoma.

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.

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 processing units in the Mid-Continent, Southwest and Rocky Mountain 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. 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.

The accounting policies for our segments are the same as those described in the summary of significant accounting policies (see Note 1).

	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

	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

XML

Significant Customers

12 Months Ended

Dec. 31, 2017

Significant Customers [Abstract]

Significant Customers

Significant Customers

We have two significant customers (Shell Oil and Sinclair), each of which has historically accounted for approximately 10% 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 revenues for the year ended December 31, 2017. The Canadian market represents our largest concentration of foreign sales and accounted for 4% of our revenues for the year ended December 31, 2017.

XML

Quarterly Information (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Information (Unaudited)

Quarterly Information (Unaudited)

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter		Year
	(In thousands, except per share data)
Year Ended December 31, 2017
Sales and other revenues	$	3,080,483		$	3,458,864		$	3,719,247	$	3,992,705	$	14,251,299
Operating costs and expenses	$	3,113,207		$	3,337,179		$	3,269,967	$	3,627,053	$	13,347,406
Income (loss) from operations (1,2)	$	(32,724	)	$	121,685		$	449,280	$	365,652	$	903,893
Income (loss) before income taxes	$	(54,571	)	$	106,069		$	446,103	$	371,262	$	868,863
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
Dividends per common share	$	0.33		$	0.33		$	0.33	$	0.33	$	1.32
Average number of shares of common stock outstanding:
Basic	176,210			176,147			176,149		176,265		176,174
Diluted	176,210			176,302			176,530		177,457		177,196
Year Ended December 31, 2016
Sales and other revenues	$	2,018,724		$	2,714,638		$	2,847,270	$	2,955,068	$	10,535,700
Operating costs and expenses	$	1,935,126		$	3,135,180		$	2,722,505	$	2,842,776	$	10,635,587
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	)
Dividends per common share	$	0.33		$	0.33		$	0.33	$	0.33	$	1.32
Average number of shares of common stock outstanding:
Basic	176,737			175,865			175,871		175,936		176,101
Diluted	176,784			175,865			175,993		176,137		176,101

(1) For 2017, income from operations reflects non-cash lower of cost or market inventory valuation charges of $11.8 million and $84.0 million for the first and second quarters, respectively, and a reduction of $111.1 million and $93.4 million for the third and fourth quarters, respectively.

(2) For 2017, income from operations reflects long-lived asset impairment charges of $23.2 million in the second quarter.

(3) For 2016, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $56.1 million and $138.5 million for the first and second quarters, respectively, and increases of $0.3 million for the third quarter and a reduction of $97.7 million for the fourth quarter.

(4) For 2016, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million , respectively, in the second quarter.

XML

Description of Business and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business

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 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 regions of the United States. In addition, we own and operate a lubricant production facility with retail and wholesale marketing of its products through a global sales network with locations in Canada, United States, Europe and China. As of December 31, 2017, 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 and operated Petro-Canada Lubricants Inc. (“PCLI”) located in Mississauga, Ontario which produces base oils and other specialized lubricant products;

• owned and operated HollyFrontier Asphalt Company (“HFC Asphalt”) which operates various asphalt terminals in Arizona, New Mexico and Oklahoma; and

• owned a 59% limited partner interest and a non-economic general partner interest in HEP, a variable interest entity (“VIE”).

On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of PCLI. The acquisition closed on February 1, 2017. See Note 2 for additional information.

Principles of Consolidation

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 Entity

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

Use of Estimates

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

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.

Marketable Securities

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

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 because it more appropriately presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated with such assets and liabilities.

Accounts Receivable

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. 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 million at December 31, 2017 and 2016, respectively.

Accounts receivable attributable to crude oil resales generally represent the sell side 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: 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'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 business 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 RINs are stated at the lower of weighted-average cost or net realizable value.

Derivative Instruments

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 13 for additional information.

Properties, plants and equipment

Properties, plants and 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.

Asset Retirement Obligations

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 million and $22.1 million at December 31, 2017 and 2016, 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, 2016 and 2015.

Intangibles and Goodwill

Intangibles, Goodwill and 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 not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our goodwill impairment testing first entails a comparison of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting unit, we measure goodwill impairment as the excess of 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 the reporting unit.

Our long-lived assets principally consist of our refining assets that are organized as refining asset groups and our lubricants and specialty products business. The refinery asset groups also constitute our individual refinery reporting units that are used for testing and measuring goodwill impairments. 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 10 for information regarding goodwill and long-lived asset impairment charges recorded during the years ended December 31, 2017 and 2016.

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

Investments in Joint Ventures: 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 accounting for investments in which we have a noncontrolling interest, yet have significant influence over the entity. Under the equity method of accounting, 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 for using the equity method of accounting. As of December 31, 2017, HEP's underlying equity and recorded investment balances in the joint ventures are $39.3 million and $85.3 million, respectively. The differences are being amortized as adjustments to HEP's pro-rata share of earnings in the joint ventures.

Revenue Recognition

Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines. 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 in cost of products sold.

Our Petro-Canada Lubricants 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, and for sales to U.S. distributors, revenues are recognized when products are shipped to the distributors, net of allowances for returns that are expected to be repurchased from the distributors. In both cases, repurchased products are subsequently sold directly to end customers.

Cost Classifications

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

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 million, $110.6 million and $107.8 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Environmental Costs

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

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.

Foreign Currency Translation

Foreign Currency Translation: The functional currency of PCLI and its affiliated non-U.S. Petro-Canada Lubricants entities includes the Canadian dollar, the euro and Chinese renminbi. Balance sheet accounts 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 corporate and other. See Note 20 for additional information on our segments.

Income Taxes

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

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 obligation that is subsequently reversed when the inventory is repurchased. For the years ended December 31,2017, 2016 and 2015, we received proceeds of $47.4 million, $57.0 million and $115.4 million and subsequently repaid $49.8 million, $58.0 million and $115.3 million, respectively, under these sell / buy transactions.

New Accounting Pronouncements

New Accounting Pronouncements

Hedge Accounting

In August 2017, Accounting Standard Update (“ASU”) 2017-12, “Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities,” was issued amending hedge accounting recognition and presentation requirements, including elimination of the requirement to separately measure and report hedge ineffectiveness, and eases certain documentation and assessment requirements. This standard has an effective date of January 1, 2019. We do not expect adoption of this standard to have a material impact on our financial condition, results of operations or cash flows.

Post-retirement Benefit Cost

In March 2017, ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost,” was issued amending 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, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017 on a prospective basis with the excess tax expense from stock-based compensation recognized as a discrete item in our provision for income taxes. Excess tax expense for the year ended December 31, 2017 totaled $0.7 million. The new standard also requires that employee taxes paid when an employer withholds shares 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 leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard. 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.

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.

XML

Acquisition (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of assets purchased and liabilities assumed in acquisition [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following summarizes the PCLI value of assets and liabilities acquired on February 1, 2017:

	(in millions)
Cash and cash equivalents	$	21.6
Accounts receivable and other current assets	118.5
Inventories	214.9
Properties, plants and equipment	438.0
Goodwill	194.8
Intangibles, precious metals and other noncurrent assets	124.3
Accounts payable and accrued liabilities	(87.4		)
Deferred income tax liabilities	(105.4		)
Other long-term liabilities	(12.6		)
Net assets acquired	$	906.7

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Financial Instruments, Owned, at Fair Value [Abstract]

Carrying Amounts and Estimated Fair Values of Marketable Securities, Derivatives and Senior Notes

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

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

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	)

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Schedule Of Earnings Per Share

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,
	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 andperformance 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

XML

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Summary Of Restricted Stock Activity

A summary of restricted stock and restricted stock unit activity and changes during the year ended December 31, 2017 is presented below:

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

Summary Of Performance Share Unit Activity

A summary of performance share unit activity and changes during the year ended December 31, 2017 is presented below:

Performance Share Units	Grants
Outstanding at January 1, 2017 (non-vested)	703,939
Granted	239,964
Vesting and transfer of ownership to recipients	(151,599	)
Forfeited	(99,643	)
Outstanding at December 31, 2017 (non-vested)	692,661

XML

Cash and Cash Equivalents and Investments in Marketable Securities (Tables)

12 Months Ended

Dec. 31, 2017

Cash, Cash Equivalents, and Short-term Investments [Abstract]

Available-For-Sale Securities

The following is a summary of our marketable securities at December 31, 2016:

	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

XML

Inventories (Tables)

12 Months Ended

Dec. 31, 2017

Inventory, Net [Abstract]

Inventory Components

Inventory consists of the following components:

	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) 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

XML

Properties, Plants and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Components Of Property, Plants And Equipment

The components of properties, plants and equipment are as follows:

	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

XML

Goodwill and Long-lived Asset Impairment (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill [Abstract]

Schedule of Goodwill [Table Text Block]

The following is a summary of our goodwill by segment:

	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

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Carrying Amounts Of Long-Term Debt

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

	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,
	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 4 for additional information on Level 2 inputs.

Principal Maturities Of Long-Term Debt

Principal maturities of long-term debt are as follows:

Years Ending December 31,	(In thousands)
2018	$	—
2019	—
2020	—
2021	—
2022	1,012,000
Thereafter	1,500,000
Total	$	2,512,000

XML

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

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 sales under hedge accounting:

	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

Summary Of Notional Amounts of Outstanding Derivatives Serving as Price Risk Hedges

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

Schedule of Realized Gain (Loss)

The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges:

	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

Schedule of Notional Amounts of Outstanding Derivatives Serving as Economic Hedges

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

Derivative Instrument	Total Outstanding Notional	Unit of Measure
NYMEX futures (WTI) - short	1,175,000	Barrels
Forward gasoline and diesel contracts - long	85,000	Barrels

Schedule of Interest Rate Derivatives

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:

	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	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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 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 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

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Provision For Income Taxes

The provision for income taxes is comprised of the following:

	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

Reconciliation Of Effective Tax Rate

The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense (benefit) as follows:

	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 Tax Assets And Liabilities

Our deferred income tax assets and liabilities as of December 31, 2017 and 2016 are as follows:

	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, 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	)

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]

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

	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	$	—

XML

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Note [Abstract]

Changes To Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2017, 2016 and 2015 are presented below:

	Years Ended December 31,
	2017		2016		2015
Common shares outstanding at January 1	177,345,266		180,234,388		196,086,090
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 restricted stock with performance feature	350,063		40,294		43,774
Forfeitures of restricted stock	(139,634	)	(16,795	)	(51,332	)
Purchase of treasury stock (1)	(342,073	)	(3,859,403	)	(16,428,574	)
Common shares outstanding at December 31	177,407,622		177,345,266		180,234,388

(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.

XML

Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2017

Other Comprehensive Income (Loss), before Tax [Abstract]

Components And Allocated Tax Effects Of Other Comprehensive Income (Loss)

The components and allocated tax effects of other comprehensive income are as follows:

	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	)

Reclassifications from Other Comprehensive Income to Income Statement

The following table presents the income statement line item effects for reclassifications out of accumulated other comprehensive income (“AOCI”):

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 Loss In Equity

Accumulated other comprehensive income in the equity section of our consolidated balance sheets includes:

	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

XML

Post-retirement Plans (Tables)

12 Months Ended

Dec. 31, 2017

Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]

Changes in Projected Benefit Obligations - PCLI

The following table sets forth the changes in the benefit obligation and plan assets of our PCLI pension plans for the eleven months ended December 31, 2017:

	February 1, 2017 to December 31, 2017
	(In thousands)
Change in plans' benefit obligations
Pension plans' benefit obligation at acquisition	$	52,155
Service cost	3,598
Interest cost	1,979
Actuarial loss	4,503
Benefits paid	(966		)
Foreign currency exchange rate changes	2,313
Pension plans' benefit obligation - end of year	$	63,582
Change in pension plans assets
Fair value of plans assets at acquisition	$	51,870
Actual return on plans assets	6,182
Benefits paid	(966		)
Foreign currency exchange rate changes	2,175
Fair value of plans assets - end of year	$	59,261
Funded status
Under-funded balance	$	(4,321	)
Amounts recognized in consolidated balance sheets
Accrued pension liability	$	(4,321	)
Amounts recognized in accumulated other comprehensive income
Cumulative actuarial loss	$	1,162

Wighted Average Assumptions Used for End of Period Benefits - PCLI

The weighted average assumptions used to determine end of period benefit obligations:

	December 31, 2017
Discount rate	3.40	%
Rate of future compensation increases	3.00	%

Net Periodic Pension Expense Components - PCLI

Net periodic pension expense consisted of the following components:

	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

Weighted Average Assumptions Used for Periodic Pension Expense - PCLI

The weighted average assumptions used to determine net periodic pension expense:

	February 1, 2017 to December 31, 2017
Discount rate	3.80	%
Rate of future compensation increases	3.00	%
Expected long-term rate of return on assets	5.75	%

Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan

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, 2017 and 2016:

	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

Weighted Average Assumptions Used

The weighted average assumptions used to determine end of period benefit obligations:

	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

Net Periodic Pension Expense

Net periodic post-retirement credit consisted of the following components:

	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	)

Weighted Average Assumptions Used to Health Care Cost Trend Rates

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

Effect of One Percent Change in Health Care Cost Trend Rates

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	)

XML

Lease Commitments (Tables)

12 Months Ended

Dec. 31, 2017

Leases, Operating [Abstract]

Schedule Of Minimum Future Rental Commitments Under Operating Leases

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

XML

Contingencies And Contractual Commitments (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Contractual Obligation, Fiscal Year Maturity Schedule

At December 31, 2017, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:

	(In thousands)
2018	$	148,716
2019	132,547
2020	119,639
2021	107,400
2022	102,884
Thereafter	857,454
Total	$	1,468,640

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information

	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

XML

Quarterly Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule Of Quarterly Information

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter		Year
	(In thousands, except per share data)
Year Ended December 31, 2017
Sales and other revenues	$	3,080,483		$	3,458,864		$	3,719,247	$	3,992,705	$	14,251,299
Operating costs and expenses	$	3,113,207		$	3,337,179		$	3,269,967	$	3,627,053	$	13,347,406
Income (loss) from operations (1,2)	$	(32,724	)	$	121,685		$	449,280	$	365,652	$	903,893
Income (loss) before income taxes	$	(54,571	)	$	106,069		$	446,103	$	371,262	$	868,863
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
Dividends per common share	$	0.33		$	0.33		$	0.33	$	0.33	$	1.32
Average number of shares of common stock outstanding:
Basic	176,210			176,147			176,149		176,265		176,174
Diluted	176,210			176,302			176,530		177,457		177,196
Year Ended December 31, 2016
Sales and other revenues	$	2,018,724		$	2,714,638		$	2,847,270	$	2,955,068	$	10,535,700
Operating costs and expenses	$	1,935,126		$	3,135,180		$	2,722,505	$	2,842,776	$	10,635,587
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	)
Dividends per common share	$	0.33		$	0.33		$	0.33	$	0.33	$	1.32
Average number of shares of common stock outstanding:
Basic	176,737			175,865			175,871		175,936		176,101
Diluted	176,784			175,865			175,993		176,137		176,101

(1) For 2017, income from operations reflects non-cash lower of cost or market inventory valuation charges of $11.8 million and $84.0 million for the first and second quarters, respectively, and a reduction of $111.1 million and $93.4 million for the third and fourth quarters, respectively.

(2) For 2017, income from operations reflects long-lived asset impairment charges of $23.2 million in the second quarter.

(3) For 2016, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $56.1 million and $138.5 million for the first and second quarters, respectively, and increases of $0.3 million for the third quarter and a reduction of $97.7 million for the fourth quarter.

(4) For 2016, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million , respectively, in the second quarter.

XML

Description of Business and Summary of Significant Accounting Policies (Details) $ in Thousands	3 Months Ended									11 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) Petroleum_Refineries mi	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Feb. 01, 2017 USD ($)	Feb. 22, 2016
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
General Partners' Contributed Capital				$ 1,100
Income tax provision												$ (12,379)	$ 19,411	$ 406,060
Income (loss) before income taxes		$ 371,262	$ 446,103	$ 106,069	$ (54,571)	$ 83,416	$ 109,867	$ (430,515)	$ 65,698			868,863	(171,534)	1,208,568
Proceeds from Inventory Repurchase Agreements												47,400	57,000	115,400
Payments under Inventory Repurchase Agreements												49,800	58,000	115,300
Excess Tax Benefit from Share-based Compensation, Operating Activities												700
Inventory Valuation Reserves		(223,833)				(332,518)				$ (223,833)		$ (223,833)	(332,518)
Goodwill, Impairment Loss													(654,084)
Number of refineries located in Tulsa, Oklahoma | Petroleum_Refineries												2
Refinery distance from main city (miles) | mi												65
Percentage of ownership interest												50.00%
Allowance for doubtful accounts		3,600				2,300				3,600		$ 3,600	2,300
Asset retirement obligation		24,800				$ 22,100				24,800		24,800	22,100
Business Combination Assets Acquired and Liabilities Assumed, Long-lived Intangible Assets		$ 100,000								100,000		100,000			$ 102,100
Amortization										$ 5,900
Turnaround and Catalyst Amortization Costs												$ 112,900	$ 110,600	107,800
Basis in Transportation Agreements		95,175,000				36,522,000				95,175,000		95,175,000	36,522,000
Third Party Transportation Agreement, Amortization Expense												$ 2,600	$ 2,000
Third Party Transportation Agreement, Accumulated Amortization		$ 26,300				$ 23,700				$ 26,300		26,300	23,700
Investments in and Advances to Affiliates, Amount of Equity		39,300								39,300		39,300
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure		$ 85,300								$ 85,300		85,300
Shares withheld for tax withholding obligations												$ 15,900	$ 4,700	$ 6,200
Transportation vehicles
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												5 years
Osage Pipeline [Member] [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage																50.00%
Frontier Pipeline [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage		50.00%								50.00%		50.00%
HEP
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Long-term Purchase Commitment, Amount		$ 56,700										$ 324,500
Percentage of ownership in variable interest entity												59.00%
Percentage of ownership interest												2.00%
Equity Method Investment, Ownership Percentage		75.00%	50.00%							75.00%		75.00%
Minimum [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Frequency of maintenance, in period												2 years
Minimum [Member] | Refining Pipeline And Terminal Facilities [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												15 years
Minimum [Member] | Buildings and Improvements [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												10 years
Minimum [Member] | Other fixed assets
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												5 years
Maximum [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Frequency of maintenance, in period												5 years
Maximum [Member] | Refining Pipeline And Terminal Facilities [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												32 years
Maximum [Member] | Buildings and Improvements [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												40 years
Maximum [Member] | Other fixed assets
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Estimated useful life of assets, minimum												30 years
Subsequent Event [Member]
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Amortization											$ 8,000
Subsequent Event [Member] | HEP
Schedule of Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Line Items]
Percentage of ownership interest	57.00%

XML

Acquisition (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
	Feb. 01, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Cash and Equivalents	$ 21,600
Current Assets, Receivables	118,500
Inventory	214,900
Property, Plant, and Equipment	438,000
Goodwill, Gross	194,800	$ 2,554,062	$ 2,554,062		$ 2,331,781
Indefinite-Lived Intangible Assets	124,300
Current Liabilities	(87,400)
Deferred Tax Liabilities	(105,400)
Noncurrent Liabilities, Other	(12,600)
Assets Acquired and Liabilities Assumed, Net	906,700
Acquisition, Cash Consideration Paid	862,100	362,000	250,000
Acquisition, Cash Consideration Paid Canadian Dollars	1,125,000
Contingent Consideration, Liability		30,600	30,600
Contingent Consideration, Account Payable		7,400	7,400
Stock Issued	$ 6,600
Revenues			14,251,299	$ 10,535,700	$ 13,237,920
Acquisition and Integration Costs		$ 27,900	27,900
Business Combination Acquiree [Member]
Business Acquisition [Line Items]
Net Income (Loss) Attributable to Parent			71,800
Revenues			$ 1,125,300

XML

Holly Energy Partners (Narrative) (Details) $ / shares in Units, $ in Thousands		3 Months Ended					6 Months Ended	9 Months Ended	12 Months Ended			20 Months Ended
	Feb. 01, 2017 USD ($) $ / shares	Mar. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) shares	Sep. 30, 2017 USD ($)	Mar. 31, 2017 USD ($) mi	Dec. 31, 2016 USD ($) $ / shares shares	Jun. 30, 2017 USD ($)	Sep. 30, 2017 mi bbl	Dec. 31, 2017 USD ($) Customers mi shares bbl	Dec. 31, 2016 USD ($) $ / shares	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($) shares	Feb. 22, 2016
Schedule of Equity Method Investments [Line Items]
Percentage of general partner interest									50.00%
Percent contribution to subsidiary revenue									83.00%
Concentration risk, precentage of total revenues									10.00%
Deferred Credits and Other Liabilities, Noncurrent					$ 38,900
Repayment of term loan				$ 39,500	39,500				$ 0	$ 350,000	$ 0
Loss on early extinguishment of debt									(12,225)	$ (8,718)	(1,370)
General Partners' Contributed Capital							$ 1,100
Partners' Capital Account, Units, Sold in Private Placement | shares			37,250,000			3,420,000
Limited Partners' Cumulative Cash Distributions			$ 2,500						2,500			$ 2,500
Proceeds from Issuance of Private Placement						$ 103,000
Partners' Capital Account, Contributions						$ 2,100
Shares Issued, Price Per Share | $ / shares	$ 28.12					$ 30.18				$ 30.18
Net proceeds from common unit offerings - HEP							52,100		$ 52,110	$ 125,870	0
Limited Partners' Capital Account, Units Issued | shares			1,538,452						1,538,452			1,538,452
Common Unit Issuance Program							$ 200,000
Acquisition, Cash Consideration Paid	$ 862,100		$ 362,000						$ 250,000
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value			$ 112,000
Remeasurement gain on pipeline interest acquisition									$ 36,254
Stock Issued During Period, Shares, Period Increase (Decrease) | shares												2,241,907
Proceeds from Issuance of Common Stock												$ 77,100
UNEV Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			75.00%						75.00%			75.00%
Frontier Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.00%						50.00%			50.00%
Length of pipeline | mi									289
Production barrel capacity per day | bbl									72,000
HEP
Schedule of Equity Method Investments [Line Items]
Percentage of ownership in variable interest entity									59.00%
Percentage of general partner interest									2.00%
Number of significant customers | Customers									2
Payments to Acquire Other Productive Assets			$ 278,000
Equity Method Investment, Ownership Percentage			75.00%	50.00%				50.00%	75.00%			75.00%
Payments to Acquire Property, Plant, and Equipment									$ 62,000
Purchase Obligation Minimum Annualized Payment									15,100
Purchase of pipeline interests - HEP									(245,446)	$ (42,627)	$ (55,032)
Length of pipeline | mi								87
Pipeline Throughput Capacity | bbl								80,000
Extinguishment of Debt, Amount					30,800
Loss on early extinguishment of debt					$ 8,700
Long-term Purchase Commitment, Amount			$ 56,700						$ 324,500
Osage Pipeline [Member] [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage													50.00%
Length of pipeline | mi					135
Subsequent Event [Member]
Schedule of Equity Method Investments [Line Items]
Partners' Capital Account, Units, Sold in Private Placement | shares		3,700,000
Proceeds from Issuance of Private Placement		$ 110,000
Shares Issued, Price Per Share | $ / shares		$ 29.73
Subsequent Event [Member] | HEP
Schedule of Equity Method Investments [Line Items]
Percentage of general partner interest		57.00%

XML

Fair Value Measurements (Estimated Fair Values Of Debt Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Financial Instruments Assets		$ 444,707
Financial Instruments Liabilities		43,655
Carrying Value [Member]
Debt Instrument [Line Items]
Financial Instruments Assets	$ 3,840
Financial Instruments Liabilities	15,735
Level 1
Debt Instrument [Line Items]
Financial Instruments Liabilities	3,360
Level 2
Debt Instrument [Line Items]
Financial Instruments Assets	3,840	444,502
Financial Instruments Liabilities	12,375	38,921
Level 3
Debt Instrument [Line Items]
Financial Instruments Assets		205
Financial Instruments Liabilities		2,759
Marketable securities [Member]
Debt Instrument [Line Items]
Financial Instruments Assets		424,148
Marketable securities [Member] | Level 2
Debt Instrument [Line Items]
Financial Instruments Assets		424,148
Commodity Contract [Member]
Debt Instrument [Line Items]
Financial Instruments Assets		14,563
Financial Instruments Liabilities		26,845
Commodity Contract [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Financial Instruments Liabilities	2,424
Commodity Contract [Member] | Level 2
Debt Instrument [Line Items]
Financial Instruments Assets		14,358
Financial Instruments Liabilities	2,424	24,086
Commodity Contract [Member] | Level 3
Debt Instrument [Line Items]
Financial Instruments Assets		205
Financial Instruments Liabilities		2,759
Currency Swap [Member]
Debt Instrument [Line Items]
Financial Instruments Liabilities		6,519
Forward Contracts [Member]
Debt Instrument [Line Items]
Financial Instruments Assets		5,905
Financial Instruments Liabilities		8,316
Forward Contracts [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Financial Instruments Assets	3,840
Financial Instruments Liabilities	1,020	8,316
Forward Contracts [Member] | Level 2
Debt Instrument [Line Items]
Financial Instruments Assets	3,840	5,905
Financial Instruments Liabilities	1,020
Interest rate swap | HEP
Debt Instrument [Line Items]
Financial Instruments Assets		91
Interest rate swap | Level 2 | HEP
Debt Instrument [Line Items]
Financial Instruments Assets		91
Foreign Currency Gain (Loss) [Member] | Level 2
Debt Instrument [Line Items]
Financial Instruments Liabilities		6,519
NYMEX futures contracts
Debt Instrument [Line Items]
Financial Instruments Liabilities	3,360	1,975
NYMEX futures contracts | Level 1
Debt Instrument [Line Items]
Financial Instruments Liabilities	3,360	1,975
NYMEX futures contracts | Level 2
Debt Instrument [Line Items]
Financial Instruments Liabilities	0	$ 0
Foreign Exchange Forward [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Financial Instruments Liabilities	8,931
Foreign Exchange Forward [Member] | Level 2
Debt Instrument [Line Items]
Financial Instruments Liabilities	$ 8,931

XML

Fair Value Measurements (Changes in Level 3 Inputs) (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Level 3 liability balance	$ 0	$ (2,554)	$ 0
Change in fair value, recognized in earnings
Change in fair value, recognized in other comprehensive income	1,626	(1,460)
Cost of products sold
Change in fair value, recognized in earnings
Change in fair value recognized in earnings	(4,664)	(1,094)
Settlement date fair value, recognized in earnings	5,757	0
Sales [Member]
Change in fair value, recognized in earnings
Settlement date fair value, recognized in earnings	$ (165)	$ 0

XML

Earnings Per Share (Schedule Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income (Loss) Attributable to Parent	$ 521,082	$ 272,014	$ 57,767	$ (45,468)	$ 53,165	$ 74,497	$ (409,368)	$ 21,253	$ 805,395	$ (260,453)	$ 740,101
Participating securities 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	176,265	176,149	176,147	176,210	175,936	175,871	175,865	176,737	176,174	176,101	188,731
Effect of dilutive variable restricted shares and performance share units									1,022	0	209
Average number of shares of common stock outstanding assuming dilution	177,457	176,530	176,302	176,210	176,137	175,993	175,865	176,784	177,196	176,101	188,940
Basic earnings (loss) per share	$ 2.94	$ 1.53	$ 0.33	$ (0.26)	$ 0.30	$ 0.42	$ (2.33)	$ 0.12	$ 4.54	$ (1.48)	$ 3.91
Diluted earnings (loss) per share	$ 2.92	$ 1.53	$ 0.33	$ (0.26)	$ 0.30	$ 0.42	$ (2.33)	$ 0.12	$ 4.52	$ (1.48)	$ 3.90
Excludes anti-dilutive restricted and performance share units									543	469	89

XML

Stock-Based Compensation (Narrative) (Details) $ / shares in Units, $ in Millions		3 Months Ended	11 Months Ended	12 Months Ended
	Feb. 01, 2017 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) $ / shares	Dec. 31, 2017 USD ($) $ / shares	Dec. 31, 2017 USD ($) plan $ / shares shares	Dec. 31, 2016 USD ($) $ / shares	Dec. 31, 2015 USD ($) $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares	472,276
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	$ 13.3
Number of share-based compensation plans | plan				2
Compensation cost attributable to share-based compensation plans			$ 6.7	$ 39.8	$ 22.8	$ 26.9
Stock Issued	$ 6.6
Shares Issued, Price Per Share | $ / shares	$ 28.12				$ 30.18
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting (transfer/conversion to common stock) | shares				817,601
Grant date fair value of restricted stock vested				$ 24.9	$ 18.4	$ 14.2
Total unrecognized compensation cost related to non-vested grants		$ 33.9	$ 33.9	$ 33.9
Weighted Average Grant Date Fair Value, Non-vested shares | $ / shares		$ 33.51	$ 33.51	$ 33.51	$ 28.87
Weighted average grant date fair value | $ / shares				$ 30.41
Total unrecognized compensation cost, weighted-average period of recognition, years				1 year 7 months
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value | $ / shares					$ 21.66	$ 49.92
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting (transfer/conversion to common stock) | shares				151,599
Grant date fair value of restricted stock vested					$ 7.4	$ 10.4
Total unrecognized compensation cost related to non-vested grants		$ 15.6	$ 15.6	$ 15.6
Weighted Average Grant Date Fair Value, Non-vested shares | $ / shares		$ 33.94	$ 33.94	$ 33.94
Total unrecognized compensation cost, weighted-average period of recognition, years				2 years 1 month
Percentage of share units awarded that will ultimately be issued, current estimate				110.00%
Common stock issued, shares | shares				138,374
Performance share units, vested in period, percentage payout				91.00%
Common stock issued, fair value				$ 6.6
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of share units awarded that will ultimately be issued, possible range				0.00%
Maximum [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock vesting period, years				3 years
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock vesting period, years		3 years
Percentage of share units awarded that will ultimately be issued, possible range				200.00%
HEP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost attributable to share-based compensation plans				$ 2.5	$ 2.7	$ 3.5

XML

Stock-Based Compensation (Summary Of Restricted Stock Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock, Nonvested [Roll Forward]
Outstanding at January 1, 2017 (non-vested)	1,188,774
Granted	1,426,106
Vesting and transfer of ownership to recipients	(817,601)
Forfeited	(71,091)
Outstanding at December 31, 2017 (non-vested)	1,726,188	1,188,774
Outstanding at January 1, 2017 (non-vested), Weighted Average Grant Date Fair Value	$ 28.87
Granted, Weighted Average Grant Date Fair Value	35.02
Vesting and transfer of ownership to recipients, Weighted Average Grant Date Fair Value	30.41
Forfeited, Weighted Average Grant Date Fair Value	30.20
Outstanding at December 31, 2017 (non-vested), Weighted Average Grant Date Fair Value	$ 33.51	$ 28.87
Outstanding at December 31, 2017 (non-vested), Aggregate Intrinsic Value	$ 88,415
Grant date fair value of restricted stock vested	$ 24,900	$ 18,400	$ 14,200
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock, Nonvested [Roll Forward]
Vesting and transfer of ownership to recipients, Weighted Average Grant Date Fair Value		$ 21.66	$ 49.92

XML

Stock-Based Compensation (Summary Of Performance Share Unit Activity) (Details) - Performance Shares [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	$ 6.6
Fair Value of performance shares vested		$ 7.4	$ 10.4
Share-based Compensation Arrangement by Share-based Payment Award, Performance Share Units, Nonvested [Roll Forward]
Outstanding at January 1, 2017 (non-vested)	703,939
Granted	239,964
Vesting and transfer of ownership to recipients	(151,599)
Forfeited	(99,643)
Outstanding at December 31, 2017 (non-vested)	692,661	703,939

XML

Cash and Cash Equivalents and Investments in Marketable Securities (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Interest income	$ 3,736	$ 2,491	$ 3,391
Available-for-sale Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Interest income	$ 300	$ 800	$ 1,900

XML

Cash and Cash Equivalents and Investments in Marketable Securities (Available-For-Sale Securities) (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Schedule of Available-for-sale Securities [Line Items]
Marketable securities, Amortized Cost	$ 424,150
Available-for-sale Securities, Gross Unrealized Gain	2
Available-for-sale Securities, Gross Unrealized Loss	(4)
Marketable securities, Fair Value (Net Carrying Amount)	424,148
State and political subdivisions debt securities
Schedule of Available-for-sale Securities [Line Items]
Marketable securities, Amortized Cost	412,462
Available-for-sale Securities, Gross Unrealized Gain	1
Available-for-sale Securities, Gross Unrealized Loss	(3)
Marketable securities, Fair Value (Net Carrying Amount)	412,460
Corporate debt securities
Schedule of Available-for-sale Securities [Line Items]
Marketable securities, Amortized Cost	4,001
Available-for-sale Securities, Gross Unrealized Gain	0
Available-for-sale Securities, Gross Unrealized Loss	0
Marketable securities, Fair Value (Net Carrying Amount)	4,001
Commercial paper
Schedule of Available-for-sale Securities [Line Items]
Marketable securities, Amortized Cost	7,687
Available-for-sale Securities, Gross Unrealized Gain	1
Available-for-sale Securities, Gross Unrealized Loss	(1)
Marketable securities, Fair Value (Net Carrying Amount)	$ 7,687

XML

Inventories (Inventory Components) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Inventory, Net [Abstract]
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)	[4]	195,762	162,548
Total inventory		$ 1,630,092	$ 1,135,676

[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] (4)Includes RINs

XML

Inventories (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 01, 2017
Inventory, Net [Abstract]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory								$ 214,900
Inventory Valuation Reserves	$ (223,833)				$ (223,833)	$ (332,518)
Lower of cost or market inventory valuation adjustment		$ (84,000)	$ (11,800)	$ 300	$ (108,685)	(291,938)	$ 226,979
Renewable Volume Obligation	$ 27,300					$ 30,500

XML

Properties, Plants and Equipment (Components Of Property, Plants And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	$ 6,523,789	$ 5,546,856
Accumulated depreciation	(1,810,515)	(1,538,408)
Properties, plants and equipment, net	4,713,274	4,008,448
Land, buildings and improvements
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	442,214	326,097
Refining facilities
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	3,904,161	3,382,369
Pipelines and terminals
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	1,484,502	1,392,898
Transportation vehicles
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	20,394	18,841
Other fixed assets
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	467,469	153,463
Construction in progress
Property, Plant and Equipment [Line Items]
Properties, plants and equipment, at cost	$ 205,049	$ 273,188

XML

Properties, Plants and Equipment (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ 19,200,000	$ 344,800,000	$ 0	$ 0
Capitalized interest		5,000,000	8,000,000	5,500,000
Depreciation expense		286,500,000	$ 247,900,000	$ 233,300,000
Refining facilities
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use		$ 0

XML

Goodwill and Long-lived Asset Impairment (Schedule Of Changes By Segment To The Carrying Amount Of Goodwill) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 01, 2017	Feb. 01, 2017
Goodwill [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ 19,200,000	$ 344,800,000	$ 0	$ 0
Goodwill, Gross		2,554,062,000		2,331,781,000		$ 194,800,000
Goodwill		2,244,744,000	2,022,463,000
Goodwill, Impaired, Accumulated Impairment Loss		(309,318,000)	(309,318,000)
Asset Impairment Charges	23,200,000	19,247,000	654,084,000	0
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount					10.00%
Refining Segment
Goodwill [Line Items]
Goodwill, Gross		2,042,790,000		2,042,790,000
Goodwill		1,733,472,000	1,733,472,000
Goodwill, Impaired, Accumulated Impairment Loss		(309,318,000)	(309,318,000)
Asset Impairment Charges		19,247,000
HEP
Goodwill [Line Items]
Goodwill, Gross		310,610,000		288,991,000
Goodwill		21,619,000	288,991,000
Goodwill, Impaired, Accumulated Impairment Loss		0	0
Asset Impairment Charges		0
324191 Petroleum Lubricating Oil and Grease Manufacturing [Member]
Goodwill [Line Items]
Goodwill, Gross		200,662,000		$ 0
Goodwill			0			$ 194,760,000
Goodwill, Foreign Currency Translation Gain (Loss)		5,902,000
Goodwill, Impaired, Accumulated Impairment Loss		0	0
Asset Impairment Charges		0
Business Combination Acquiree [Member]
Goodwill [Line Items]
Goodwill		216,379,000
HEP
Goodwill [Line Items]
Goodwill		$ 310,610,000	$ 288,991,000
Property, Plant and Equipment [Member]
Goodwill [Line Items]
Asset Impairment Charges	$ 4,000,000

XML

Environmental (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 01, 2017
Loss Contingencies [Line Items]
Environmental remediation costs	$ 13.1	$ 6.6	$ 14.7
Accrued environmental liability	$ 103.7	96.4
Length of Time for Environmental Remediation	30 years
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				$ 2.9
Other Noncurrent Liabilities [Member]
Loss Contingencies [Line Items]
Accrued environmental liability	$ 89.6	$ 82.9

XML

Debt (Narrative) (Details) - USD ($)		3 Months Ended				9 Months Ended	12 Months Ended
	Apr. 29, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 31, 2017	Nov. 30, 2016	Sep. 30, 2016	Jul. 31, 2016	Mar. 31, 2016	Jun. 30, 2015
Debt Instrument [Line Items]
Maximum borrowing capacity under revolving credit agreement		$ 1,350,000,000					$ 1,350,000,000
Line of Credit Facility, Expiration Date		Feb. 01, 2022
Proceeds from Lines of Credit							26,000,000
Repayments of Lines of Credit							(26,000,000)
Letters of Credit Outstanding, Amount		$ 2,800,000					$ 2,800,000
Effective interest rate on debt		0.00%					0.00%	2.98%
Long-term debt		$ 2,498,993,000					$ 2,498,993,000	$ 2,235,137,000
Loss on early extinguishment of debt							(12,225,000)	(8,718,000)	$ (1,370,000)
Repayment of term loan			$ 39,500,000		$ 39,500,000		$ 0	350,000,000	$ 0
Proceeds from Loans	$ 350,000,000
Debt Instrument, Maturity Date							Apr. 01, 2026
Senior Notes, Noncurrent											$ 750,000,000			$ 250,000,000
Plains [Member] | Lease [Member]
Debt Instrument [Line Items]
Loss on early extinguishment of debt						$ 8,700,000
Proceeds from Sale of Machinery and Equipment						$ 40,000,000
HEP
Debt Instrument [Line Items]
Maximum borrowing capacity under revolving credit agreement		1,400,000,000					$ 1,400,000,000
Proceeds from Lines of Credit							969,000,000
Repayments of Lines of Credit							(510,000,000)
Borrowings outstanding under revolving credit agreement		1,012,000,000					1,012,000,000	553,000,000
Senior notes		525,120,000					525,120,000	723,750,000
Loss on early extinguishment of debt					8,700,000
Extinguishment of Debt, Amount					$ 30,800,000
Nine Point Eight Seven Five Percentage Senior Notes Due Two Thousand Seventeen Member
Debt Instrument [Line Items]
Stated interest rate, senior notes															9.875%
Letter of Credit [Member] | HEP
Debt Instrument [Line Items]
Line of Credit Facility, Accordion Feature		$ 300,000,000					300,000,000
Line of Credit Facility, Expiration Date		Jul. 01, 2022
Line of Credit Facility, Capacity Available for Trade Purchases		$ 50,000,000					50,000,000
Five Point Eight Seven Five Percentage Senior Notes Due Two Thousand Twenty-Six [Member] [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes					5.875%
Senior notes		1,113,470,000					1,113,470,000	1,022,500,000
Senior Notes, Noncurrent		1,000,000,000					1,000,000,000	1,000,000,000
Debt Instrument, Unamortized Discount		$ 8,315,000					$ 8,315,000	8,775,000
6.875% Senior Notes Due 2018
Debt Instrument [Line Items]
Stated interest rate, senior notes		6.875%		6.875%			6.875%
Loss on early extinguishment of debt				$ 1,400,000
Redemption premium on early extinguishment of debt				(5,200,000)
Amortization of Debt Discount (Premium)				3,800,000
Senior Notes, Noncurrent				150,000,000
Extinguishment of Debt, Amount				$ 155,200,000
Other Debt Obligations [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date						Apr. 01, 2019
8.25% Senior Notes Due 2018 | HEP
Debt Instrument [Line Items]
Stated interest rate, senior notes		8.25%					8.25%
6.5% Senior Notes Due 2020 | HEP
Debt Instrument [Line Items]
Stated interest rate, senior notes		6.50%					6.50%
Long-term debt								297,519,000
Loss on early extinguishment of debt					$ 12,200,000
Redemption premium on early extinguishment of debt					9,800,000
Senior Notes					$ 300,000,000
Senior Notes Aggregate Redemption Amount										$ 309,800,000
Debt Instrument, Maturity Date						Mar. 01, 2020
Senior Notes, Noncurrent								300,000,000
Debt Instrument, Unamortized Discount								2,481,000		$ 2,400,000
Six Percent Senior Notes Due Two Thousand Twenty Four [Member] [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes		6.00%					6.00%
Six Percent Senior Notes Due Two Thousand Twenty Four [Member] [Member] | HEP
Debt Instrument [Line Items]
Stated interest rate, senior notes		6.00%					6.00%
Debt Instrument, Maturity Date							Aug. 01, 2024
Senior Notes, Noncurrent		$ 500,000,000					$ 500,000,000	400,000,000				$ 100,000,000	$ 400,000,000
Debt Instrument, Unamortized Discount		$ 4,692,000					$ 4,692,000	$ 6,607,000

XML

Debt (Carrying Amounts Of Long-Term Debt) (Details) - USD ($)	Dec. 31, 2017	Mar. 31, 2017	Jan. 31, 2017	Dec. 31, 2016	Nov. 30, 2016	Sep. 30, 2016	Jul. 31, 2016	Mar. 31, 2016
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 2,498,993,000			$ 2,235,137,000
Senior Notes, Noncurrent					$ 750,000,000			$ 250,000,000
Total	2,512,000,000
Long-term Debt and Capital Lease Obligations	2,498,993,000			2,235,137,000
HEP
Debt Instrument [Line Items]
Borrowings outstanding under revolving credit agreement	1,012,000,000			553,000,000
Long-term Debt and Capital Lease Obligations	1,507,308,000			1,243,912,000
Five Point Eight Seven Five Percentage Senior Notes Due Two Thousand Twenty-Six [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.875%
Senior Notes, Noncurrent	1,000,000,000			1,000,000,000
Debt Instrument, Unamortized Discount	(8,315,000)			(8,775,000)
Total	$ 991,685,000			991,225,000
Six Percent Senior Notes Due Two Thousand Twenty Four [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Six Percent Senior Notes Due Two Thousand Twenty Four [Member] [Member] | HEP
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Senior Notes, Noncurrent	$ 500,000,000			400,000,000		$ 100,000,000	$ 400,000,000
Debt Instrument, Unamortized Discount	(4,692,000)			(6,607,000)
Total	$ 495,308,000			393,393,000
8.25% Senior Notes Due 2018 | HEP
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
6.5% Senior Notes Due 2020 | HEP
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Long-term Debt, Excluding Current Maturities				297,519,000
Senior Notes, Noncurrent				300,000,000
Debt Instrument, Unamortized Discount			$ (2,400,000)	$ (2,481,000)

XML

Debt (Principal Maturities Of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Debt Disclosure [Abstract]
Next Twelve Months	$ 0
Year Two	0
Year Three	0
Year Four	0
Year Five	1,012,000
Thereafter	1,500,000
Total	$ 2,512,000

XML

Derivative Instruments and Hedging Activities Derivatives and Hedging Instruments Gains Losses due to Settlements Hedge Ineffectiveness (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Trading Activity, Gains and Losses, Net [Line Items]
Unrealized Gain (Loss) on Cash Flow Hedging Instruments	$ 14,538	$ 25,139	$ (52,495)
Change in Fair Value	2,831	(17,018)	(3,983)
Gain (Loss) Reclassified to Earnings due to Settlements	10,627	41,077	(49,592)
Amortization of discontinued hedges reclassified to earnings	1,080	1,080	1,080
Gain (Loss) recognized in earnings due to settlements	(11,707)	(42,157)	48,512
Derivative, Net Hedge Ineffectiveness Gain (Loss)	(54)	0	4,649
Sales [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Gain (Loss) recognized in earnings due to settlements	7,836	(20,293)	245,819
Derivative, Net Hedge Ineffectiveness Gain (Loss)			(274)
Cost of products sold
Trading Activity, Gains and Losses, Net [Line Items]
Gain (Loss) recognized in earnings due to settlements	(299)		(179,700)
Derivative, Net Hedge Ineffectiveness Gain (Loss)			4,376
Operating expenses
Trading Activity, Gains and Losses, Net [Line Items]
Gain (Loss) recognized in earnings due to settlements	(19,244)	(21,864)	(17,607)
Derivative, Net Hedge Ineffectiveness Gain (Loss)	$ (54)	$ 0	$ 547

XML

Derivative Instruments and Hedging Activities Notional Contracts by Derivative Type (Details)	3 Months Ended
	Dec. 31, 2017 MMBTU bbl
Produced Gasoline Member | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	250,000
Natural Gas - long [Member] | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	7,200,000
NYMEX WTI Short [Member] | Economic Hedges [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	1,175,000
Forward Contracts [Member] | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	276,751
Forward Contracts [Member] | Economic Hedges [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	85,000
Maturing in Next Twelve Months [Member] | Produced Gasoline Member | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	250,000
Maturing in Next Twelve Months [Member] | Natural Gas - long [Member] | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,800,000
Maturing in Next Twelve Months [Member] | Forward Contracts [Member] | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	276,751
Maturing in Year Two [Member] | Natural Gas - long [Member] | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,800,000
Maturing in Year Four [Member] | Natural Gas - long [Member] | Price Risk Derivative [Member]
economic hedges by derivative type [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,800,000

XML

Derivative Instruments and Hedging Activities Location of Gain Loss in Income Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Economic Hedges, Gain (Loss)	$ 5,521	$ (6,133)	$ 36,079
Cost of products sold
Derivative Instruments, Gain (Loss) [Line Items]
Economic Hedges, Gain (Loss)	(12,327)	(6,889)	48,082
Operating expenses
Derivative Instruments, Gain (Loss) [Line Items]
Economic Hedges, Gain (Loss)	(6,697)	7,276	(12,003)
Other Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Economic Hedges, Gain (Loss)	$ 24,545	$ (6,520)	$ 0

XML

Derivative Instruments and Hedging Activities Interest Rate Swaps (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Change in Fair Value	$ (2,831)	$ 17,018	$ 3,983
Gain (Loss) Reclassified to Earnings due to Settlements	(10,627)	(41,077)	49,592
Gain (Loss) recognized in earnings due to settlements	(11,707)	(42,157)	48,512
HEP
Derivative [Line Items]
Change in Fair Value	88	(607)	(1,864)
Gain (Loss) Reclassified to Earnings due to Settlements	(179)	508	2,100
Pretax effect on accumulated other comprehensive income and earnings	(91)	(99)	236
Interest Expense [Member] | HEP
Derivative [Line Items]
Gain (Loss) recognized in earnings due to settlements	$ 179	$ (508)	$ (2,100)

XML

Derivative Instruments and Hedging Activities (Summary Of Balance Sheet Locations And Related Fair Values Of Outstanding Derivative Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	$ 3,840	$ 9,484
Derivative Liability, Fair Value, Net Liability	6,804	32,580
Prepayments and other
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	3,840	9,484
Accrued Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Net Liability	5,365	32,580
Other Long Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Net Liability	1,439
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,067	91
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative, Fair Value, Net	3,067	91
Derivative Liability, Fair Value, Gross Liability	2,842	16,163
Derivative Liability, Fair Value, Gross Asset	0	431
Derivative Liability, Fair Value, Net Liability	2,842	15,732
Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,424	13,185
Derivative Liability, Fair Value, Gross Asset	0	431
Derivative Liability, Fair Value, Net Liability	2,424	12,754
Designated as Hedging Instrument [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,067
Derivative Asset, Fair Value, Gross Liability	0
Derivative, Fair Value, Net	3,067
Derivative Liability, Fair Value, Gross Liability	418	2,978
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Net Liability	418	2,978
Designated as Hedging Instrument [Member] | Interest rate swap
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		91
Derivative Asset, Fair Value, Gross Liability		0
Derivative, Fair Value, Net		91
Derivative Liability, Fair Value, Gross Liability		0
Derivative Liability, Fair Value, Gross Asset		0
Derivative Liability, Fair Value, Net Liability		0
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	773	10,149
Derivative Asset, Fair Value, Gross Liability	0	(756)
Derivative, Fair Value, Net	773	9,393
Derivative Liability, Fair Value, Gross Liability	3,962	26,735
Derivative Liability, Fair Value, Gross Asset	0	(9,887)
Derivative Liability, Fair Value, Net Liability	3,962	16,848
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		4,244
Derivative Asset, Fair Value, Gross Liability		(756)
Derivative, Fair Value, Net		3,488
Derivative Liability, Fair Value, Gross Liability		12,903
Derivative Liability, Fair Value, Gross Asset		(9,887)
Derivative Liability, Fair Value, Net Liability		3,016
Not Designated as Hedging Instrument [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	773	5,905
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative, Fair Value, Net	773	5,905
Derivative Liability, Fair Value, Gross Liability	602	5,338
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Net Liability	602	5,338
Not Designated as Hedging Instrument [Member] | Nymex Futures Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Derivative Asset, Fair Value, Gross Liability		0
Derivative, Fair Value, Net		0
Derivative Liability, Fair Value, Gross Liability	3,360	1,975
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Net Liability	$ 3,360	1,975
Not Designated as Hedging Instrument [Member] | Foreign Exchange Forward [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6,519
Derivative Liability, Fair Value, Gross Asset		0
Derivative Liability, Fair Value, Net Liability		$ 6,519

XML

Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
	Feb. 01, 2017	Dec. 31, 2017	Dec. 31, 2017
Derivative [Line Items]
Unrealized Gain (Loss) on Price Risk Cash Flow Derivatives, before Tax			$ (1.3)
Derivative, Maturity Date		Jan. 01, 2021
Acquisition, Cash Consideration Paid Canadian Dollars	$ 1,125.0
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			$ 0.1

XML

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%		35.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ (307,101)
Unrecognized Tax Benefits	$ 53,752	$ 53,752	$ 22,137	$ 0	$ 0
Tax Credit Carryforward, Expiration Date		16 years
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		$ 31,615	$ 22,137	$ 0
Effective Income Tax Rate Reconciliation, Tax Contingency, Domestic, Percent	25.00%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	$ 315,000
Tax Year 2011 [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Examination, Year under Examination		2012
Tax Year 2013 [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Examination, Year under Examination		2013
OKLAHOMA
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	9,700	$ 9,700
KANSAS
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	$ 16,800	$ 16,800

XML

Income Taxes (Provision For Income Taxes) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal, Current		$ 102,786	$ (71,878)	$ 480,446
State, Current		2,760	(7,304)	71,750
Current Foreign Tax Expense (Benefit)		19,597	0	0
Federal, Deferred		(156,767)	100,208	(127,714)
State, Deferred		28,527	(1,615)	(18,422)
Deferred Foreign Income Tax Expense (Benefit)	$ 1,400	(9,282)	0	0
Income tax provision total		$ (12,379)	$ 19,411	$ 406,060

XML

Income Taxes (Reconciliation Of Effective Tax Rate) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Tax computed at statutory rate	$ 304,102	$ (60,037)	$ 422,999
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(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	0	119,722
Other	8,571	(3,485)	2,031
Income tax provision total	$ (12,379)	$ 19,411	$ 406,060

XML

Income Taxes (Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, gross	$ 75,398	$ 117,249
Deferred tax liabilities, gross	(723,183)	(737,663)
Deferred taxes, net	(647,785)	(620,414)
Property, Plant and Equipment [Member]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax liabilities, noncurrent	(560,957)	(618,053)
Accrued employee benefits
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent	14,685	21,355
Postretirement Benefit Costs [Member]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent	10,358	10,024
Reserve for Environmental Costs [Member]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent	28,657	41,152
Deferred Tax Liability Derivatives [Member]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent		7,396
Deferred Tax Asset, Derivatives [Domain]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent	16	7,396
Inventory Valuation Reserve [Member]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent		0
Deferred tax liabilities, noncurrent	(35,501)	(8,341)
Deferred turnaround costs
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax liabilities, noncurrent	(58,645)	(83,993)
Net operating loss and tax credit carryforward [Member]
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent	21,682	23,203
HEP
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax liabilities, noncurrent	(62,321)	(27,276)
Other
Deferred Income Taxes Assets Liabilities [Line Items]
Deferred tax assets, noncurrent	0	$ 14,119
Deferred tax liabilities, noncurrent	$ (5,759)

XML

Income Taxes (Reconciliation Of Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized Tax Benefits, Beginning of Period	$ 22,137	$ 0	$ 0
Additions based on tax positions related to the current year	31,615	22,137	0
Unrecognized Tax Benefits, End of Period	$ 53,752	$ 22,137	$ 0

XML

Income Taxes Income Taxes (Foreign) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure Foreign [Abstract]
Effective Income Tax Rate Reconciliation, Tax Contingency, Domestic, Percent	25.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%			35.00%
Effective Income Tax Rate Reconciliation, Repatriation of Foreign Earnings, Percent	15.50%	35.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent		38.00%	20.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount	$ 6,500
Deferred Foreign Income Tax Expense (Benefit)	$ 1,400		$ (9,282)	$ 0	$ 0

XML

Stockholders' Equity (Changes To Equity) (Details) - shares		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Common Shares Outstanding [Roll Forward]
Common shares outstanding at January 1		177,345,266	180,234,388	196,086,090
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 restricted stock with performance feature		350,063	40,294	43,774
Forfeitures of restricted stock		(139,634)	(16,795)	(51,332)
Purchase of treasury stock	[1]	(342,073)	(3,859,403)	(16,428,574)
Common shares outstanding at December 31		177,407,622	177,345,266	180,234,388
Shares withheld for the payment of taxes		342,073	147,922	151,967

[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.

XML

Stockholders' Equity (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Authorized share repurchase	$ 1,000,000
Stock repurchase program, value	178,800
Value of shares withheld related to tax withholding for share-based compensation	$ 15,926	$ 4,677	$ 6,242

XML

Other Comprehensive Income (Loss) (Components And Allocated Tax Effects Of Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income (Loss), before Tax [Abstract]
Foreign currency translation adjustment	$ 22,151	$ 0	$ 0
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax	7,774
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	14,377
Net unrealized gain (loss) on marketable securities, before tax	(4)	104	38
Net Unrealized gain (loss) on available-for-sale securities, tax expense (benefit)	(1)	40	14
Net unrealized gain (loss) on available-for-sale securities, after-tax	(3)	64	24
Net Unrealized Gain (Loss) on Hedging Activities, Before-Tax	14,447	25,040	(52,259)
Net Unrealized Gain (Loss) on Hedging Activities, Tax	5,613	9,713	(20,282)
Net Unrealized Gain (Loss) on Hedging Activities, Net of Tax	8,834	15,327	(31,977)
Net change in other post-retirement benefit obligations, before tax	(5,807)	(1,113)	79
Net change in other post-retirement benefit obligations, tax	(2,037)	(431)	31
Net change in other post-retirement benefit obligations, after tax	(3,770)	(682)	48
Other comprehensive income (loss) before income taxes	30,787	24,031	(52,142)
Other comprehensive income (loss), Tax Expense (Benefit)	11,349	9,322	(20,237)
Other comprehensive income (loss)	19,438	14,709	(31,905)
Less other comprehensive income (loss) attributable to noncontrolling interest, Before-Tax	(57)	(58)	144
Less other comprehensive income (loss) attributable to noncontrolling interest, Tax Expense (Benefit)	0	0	0
Less other comprehensive income (loss) attributable to noncontrolling interest, After-Tax	(57)	(58)	144
Other comprehensive income (loss) attributable to HollyFrontier stockholders, Before-Tax	30,844	24,089	(52,286)
Other comprehensive income (loss) attributable to HollyFrontier stockholders, Tax Expense (Benefit)	11,349	9,322	(20,237)
Other comprehensive income (loss) attributable to HollyFrontier stockholders, After-Tax	$ 19,495	$ 14,767	$ (32,049)

XML

Other Comprehensive Income (Loss) (Accumulated Other Comprehensive Loss In Equity) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Other Comprehensive Income (Loss), before Tax [Abstract]
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	$ 14,377
Unrealized gain on post-retirement benefit obligations	16,939	$ 20,055
Accumulated Other Comprehensive Income (Loss), Unrealized Loss on Pension Obligation	(654)
Unrealized gain (loss) on marketable securities	0	3
Unrealized gain (loss) on hedging instruments	(793)	(9,446)
Accumulated other comprehensive income (loss)	$ 29,869	$ 10,612

XML

Other Comprehensive Income (Loss) Other Comprehensive Income (Loss) Amounts Reclassified to Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Income tax expense (benefit)									$ (12,379)	$ 19,411	$ 406,060
Net of tax									881,242	(190,945)	802,508
Sales and other revenues	$ (3,992,705)	$ (3,719,247)	$ (3,458,864)	$ (3,080,483)	$ (2,955,068)	$ (2,847,270)	$ (2,714,638)	$ (2,018,724)	(14,251,299)	(10,535,700)	(13,237,920)
Operating expenses									(1,294,234)	(1,018,839)	(1,060,373)
Selling, general and Administrative Expense									(264,874)	(125,648)	(120,846)
Interest Expense									(117,597)	(72,192)	(43,470)
Noncontrolling interest									(75,847)	(69,508)	(62,407)
Net Income (Loss) Attributable to Parent	$ 521,082	$ 272,014	$ 57,767	$ (45,468)	$ 53,165	$ 74,497	$ (409,368)	$ 21,253	805,395	(260,453)	740,101
Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Reclassifications for the period									(4,988)	(23,847)	31,235
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Interest Income									0	(23)	(51)
Gain on sale of assets									0	0	42
Gain (Loss) on Sale of Securities, Net									0	(23)	(9)
Income tax expense (benefit)									0	(9)	(3)
Net of tax										(14)	(6)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Income tax expense (benefit)									(4,490)	(16,387)	18,454
Net of tax									(7,038)	(26,278)	27,958
Before tax									(11,528)	(42,665)	46,412
Noncontrolling interest									(74)	320	1,273
Net Income (Loss) Attributable to Parent									(7,112)	(25,958)	29,231
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Commodity Contract [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Sales and other revenues									7,836	(20,293)	245,819
Cost of products sold									(299)	0	(179,700)
Operating expenses									(19,244)	(21,864)	(17,607)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Interest Rate Contract [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Interest Expense									179	(508)	(2,100)
Accumulated Defined Benefit Plans Adjustment [Member] | Other Pension, Postretirement and Supplemental Plans [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Income tax expense (benefit)									1,347	1,348	1,277
Net of tax									2,134	2,134	2,022
Cost of products sold									87	130	271
Operating expenses									3,012	2,989	2,681
Selling, general and Administrative Expense									382	363	347
Before tax									3,481	3,482	3,299
Accumulated Defined Benefit Plans Adjustment [Member] | Other Pension Plan [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Other Comprehensive Income (Loss) Reclassified to Income Statement [Line Items]
Income tax expense (benefit)									(7)	(6)	(8)
Net of tax									(10)	(9)	(12)
Selling, general and Administrative Expense									$ 17	$ 15	$ 20

XML

Post-retirement Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 0.2
Pension expense	0.1	$ 0.1	$ 0.1
Accrued liability	2.7	2.7
Projected benefit obligations under this plan	2.7
Defined Contribution Plan, Employer Discretionary Contribution Amount	17.6	$ 17.5	$ 17.2
Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	1.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	1.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	1.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	1.7
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	1.7
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	8.2
Business Combination Acquiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 52.8

XML

Post-retirement Plans (Changes in Benefit Obligation and Plan Assets) (Details) - USD ($) $ in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Pension plan's benefit obligation - beginning of year		$ 18,992	$ 21,201
Service cost	$ 3,598	1,511	1,294	$ 1,694
Interest cost	1,979	987	787	819
Participant contributions		181	244
Amendments		0	21
Benefits paid		(1,800)	(2,171)
Actuarial loss (gain)		1,058	(2,384)
Foreign currency exchange rate changes		358	0
Pension plan's benefit obligation - end of year	29,499	29,499	18,992	21,201
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets - beginning of year		0	0
Employer contributions		1,542	1,927
Fair value of plan assets - end of year	0	0	0	$ 0
Participant contributions		258	244
Under-funded balance	(29,499)	(29,499)	(18,992)
Accrued post-retirement plan liability	(29,499)	(29,499)	(18,992)
Cumulative actuarial (loss) gain	(287)	(287)	771
Prior service credit	28,953	28,953	32,434
Total	28,666	28,666	$ 33,205
Business Combination Acquiree [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
PCLI acquisition		8,212
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Pension plan's benefit obligation - beginning of year	52,155
Service cost	3,598
Interest cost	1,979
Benefits paid	(966)
Actuarial loss (gain)	4,503
Foreign currency exchange rate changes	2,313
Pension plan's benefit obligation - end of year	63,582	63,582
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets - beginning of year	51,870
Actual return on plans assets	6,182
Foreign currency exchange rate changes	2,175
Fair value of plan assets - end of year	59,261	59,261
Under-funded balance	(4,321)	(4,321)
Accrued post-retirement plan liability	(4,321)	(4,321)
Cumulative actuarial (loss) gain	$ 1,162	$ 1,162

XML

Post-retirement Plans (Weighted Average Assumptions Used to Determine End of Period Benefit Obligations) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.35%	3.75%
Current health care trend rate	7.00%	7.00%
Ultimate health care trend rate	5.00%	5.00%
Year rate reaches ultimate trend rate	2028	2030
Business Combination Acquiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.40%
Rate of future compensation increases	3.00%
Current health care trend rate	6.50%
Ultimate health care trend rate	5.00%
Year rate reaches ultimate trend rate	2022

XML

Post-retirement Plans (Net Periodic Pension Expense) (Details) - USD ($) $ in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 3,598	$ 1,511	$ 1,294	$ 1,694
Interest cost	1,979	987	787	819
Amortization of Prior Service Cost (Credit)		(3,481)	(3,482)	(3,482)
Amortization of net loss		0	0	183
Net periodic post-retirement credit		$ (983)	$ (1,401)	$ (786)
Expected return on plans assets	2,841
Net periodic pension expense	$ 2,736

XML

Post-retirement Plans (Weighted Average Assumptions Used to Determine Net Periodic Benefit Expense) (Details) - Business Combination Acquiree [Member]	11 Months Ended
	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	3.80%
Rate of future compensation increases	3.00%
Expected long-term rate of return on assets	5.75%

XML

Post-retirement Plans (Weighted Average Assumptions Used for Health Care Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate	3.35%	3.75%
Current health care trend rate	7.00%	7.00%
Ultimate health care trend rate	5.00%	5.00%
Year rate reaches ultimate trend rate	2028	2030
Business Combination Acquiree [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate	3.40%
Current health care trend rate	6.50%
Ultimate health care trend rate	5.00%
Year rate reaches ultimate trend rate	2022
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate	3.75%	3.90%	3.60%
Current health care trend rate	7.00%	8.00%	8.00%
Ultimate health care trend rate	5.00%	5.00%	5.00%
Year rate reaches ultimate trend rate	2030	2041	2042
Other Postretirement Benefits Plan [Member] | Business Combination Acquiree [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate	3.80%
Current health care trend rate	6.50%
Ultimate health care trend rate	5.00%
Year rate reaches ultimate trend rate	2022

XML

Post-retirement Plans (Effect of One Percent Change in Health Care Cost Trend Rates) (Details) - Postretirement Health Coverage [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($)
Defined Benefit Plan Disclosure [Line Items]
One Percent Increase, Service Cost	$ 175
One Percentage Point Decrease on Service Cost	(146)
One Percentage Point Increase on Accumulated Post-retirement Benefit Obligation	1,393
One Percentage Point Decrease on Accumulated Post-retirement Benefit Obligation	(1,204)
Interest Expense [Member]
Defined Benefit Plan Disclosure [Line Items]
One Percent Increase, Service Cost	48
One Percentage Point Decrease on Service Cost	$ (42)

XML

Post-retirement Plans (PCLI Pension) (Details) - USD ($) $ in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Pension plan's benefit obligation - beginning of year		$ 18,992	$ 21,201
Service cost	$ 3,598	1,511	1,294	$ 1,694
Interest cost	1,979	987	787	819
Participant contributions		181	244
Amendments		0	21
Benefits paid		(1,800)	(2,171)
Actuarial loss (gain)		1,058	(2,384)
Foreign currency exchange rate changes		358	0
Pension plan's benefit obligation - end of year	29,499	29,499	18,992	21,201
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets - beginning of year		0	0
Employer contributions		1,542	1,927
Participant contributions		258	244
Fair value of plan assets - end of year	0	0	0	$ 0
Under-funded balance	29,499	29,499	18,992
Accrued post-retirement plan liability	(29,499)	(29,499)	(18,992)
Cumulative actuarial (loss) gain	(287)	(287)	771
Prior service credit	28,953	28,953	32,434
Total	28,666	28,666	$ 33,205
Business Combination Acquiree [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Pension plan's benefit obligation - beginning of year	52,155
PCLI acquisition		8,212
Service cost	3,598
Interest cost	1,979
Benefits paid	(966)
Actuarial loss (gain)	4,503
Foreign currency exchange rate changes	2,313
Pension plan's benefit obligation - end of year	63,582	63,582
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets - beginning of year	51,870
Fair value of plan assets - end of year	59,261	59,261
Under-funded balance	4,321	4,321
Accrued post-retirement plan liability	(4,321)	(4,321)
Cumulative actuarial (loss) gain	$ 1,162	$ 1,162

XML

Lease Commitments (Schedule Of Minimum Future Rental Commitments Under Operating Leases) (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Leases, Operating [Abstract]
Minimum lease commitments due in twelve months	$ 82,345
Minimum lease commitments due in year two	74,987
Minimum lease commitments due in year three	70,654
Minimum lease commitments due in year four	58,571
Minimum lease commitments due in year five	51,019
Thereafter	88,626
Total	$ 426,202

XML

Lease Commitments (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leased Assets [Line Items]
Rental expense	$ 95.7	$ 93.2	$ 107.3

XML

Contingencies And Contractual Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Transportation and Storage Contracts, Fiscal Year Maturity
Next Twelve Months	$ 148,716
Year Two	132,547
Year Three	119,639
Year Four	107,400
Year Five	102,884
Thereafter	857,454
Total	1,468,640
Transportation and storage costs	140,500	$ 135,100	$ 137,700
Receivables, Long-term Contracts or Programs	26,000
Business Combination, Contingent Consideration Arrangements, Change in Amount of Contingent Consideration, Liability	$ 20,000

XML

Segment Information (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss		$ 654,084
Revenue for reportable segment	$ 14,251,299	$ 10,535,700	$ 13,237,920
HEP
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	75.00%			50.00%
Frontier Pipeline [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Frontier Pipeline [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

XML

Segment Information (Schedule Of Segment Reporting Information) (Details) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Sales and other revenues	$ 3,992,705		$ 3,719,247		$ 3,458,864		$ 3,080,483		$ 2,955,068		$ 2,847,270		$ 2,714,638		$ 2,018,724		$ 14,251,299	$ 10,535,700	$ 13,237,920
Intersegment Revenues																	0	0	0
Revenues																	14,251,299	10,535,700	13,237,920
Refining and Marketing Costs																	11,467,799	8,765,927	10,239,218
Lower of cost or market inventory valuation adjustment	93,400		(111,100)						(97,700)				138,500		56,100		(108,685)	(291,938)	226,979
Operating Expenses																	1,294,234	1,018,839	1,060,373
Selling, General and Administrative Expense																	264,874	125,648	120,846
Depreciation, Depletion and Amortization																	409,937	363,027	346,151
Income (loss) from operations	365,652	[1],[2]	$ 449,280	[1],[2]	121,685	[1],[2]	$ (32,724)	[1],[2]	112,292	[3],[4]	$ 124,765	[3],[4]	$ (420,542)	[3],[4]	$ 83,598	[3],[4]	903,893	(99,887)	1,244,353
Income (Loss) from Equity Method Investments																	12,510	14,213	(3,738)
Goodwill, Impairment Loss																		654,084
Asset Impairment Charges					$ 23,200												19,247	654,084	0
Property, Plant and Equipment, Additions																	272,259	479,790	676,155
Assets	10,692,154								9,435,661								10,692,154	9,435,661	8,388,299
Refining
Segment Reporting Information [Line Items]
Sales and other revenues																	12,579,672	10,002,831	12,677,901
Intersegment Revenues																	338,390	317,884	361,211
Revenues																	12,918,062	10,320,715	13,039,112
Refining and Marketing Costs																	11,009,345	9,003,505	10,472,268
Lower of cost or market inventory valuation adjustment																	(107,479)	(287,848)	225,736
Operating Expenses																	1,006,675	909,724	940,629
Selling, General and Administrative Expense																	103,067	92,297	91,279
Depreciation, Depletion and Amortization																	289,434	281,701	273,091
Income (loss) from operations																	597,773	(332,748)	1,036,109
Income (Loss) from Equity Method Investments																	0	0	0
Goodwill, Impairment Loss																		654,084
Asset Impairment Charges																	19,247
Property, Plant and Equipment, Additions																	176,533	357,407	461,326
Assets	6,474,666								6,048,091								6,474,666	6,048,091	6,286,154
324191 Petroleum Lubricating Oil and Grease Manufacturing [Member]
Segment Reporting Information [Line Items]
Sales and other revenues																	1,594,036	464,359	493,282
Intersegment Revenues																	0	0	0
Revenues																	1,594,036	464,359	493,282
Refining and Marketing Costs																	1,093,984	377,136	414,553
Lower of cost or market inventory valuation adjustment																	(1,206)	(4,090)	1,243
Operating Expenses																	222,461	13,867	14,042
Selling, General and Administrative Expense																	105,112	2,899	2,615
Depreciation, Depletion and Amortization																	31,894	620	254
Income (loss) from operations																	141,791	73,927	60,575
Income (Loss) from Equity Method Investments																	0	0	0
Goodwill, Impairment Loss																		0
Asset Impairment Charges																	0
Property, Plant and Equipment, Additions																	31,464	5,708	7,685
Assets	1,610,472								465,715								1,610,472	465,715	320,510
HEP
Segment Reporting Information [Line Items]
Sales and other revenues																	77,225	68,927	66,654
Intersegment Revenues																	377,137	333,116	292,221
Revenues																	454,362	402,043	358,875
Refining and Marketing Costs																	0	0	0
Lower of cost or market inventory valuation adjustment																	0	0	0
Operating Expenses																	137,605	123,984	105,554
Selling, General and Administrative Expense																	14,323	12,532	12,556
Depreciation, Depletion and Amortization																	77,660	68,811	61,690
Income (loss) from operations																	224,774	196,716	179,075
Income (Loss) from Equity Method Investments																	12,510	14,213	4,803
Goodwill, Impairment Loss																		0
Asset Impairment Charges																	0
Property, Plant and Equipment, Additions																	44,810	107,595	193,121
Assets	2,191,984								1,920,487								2,191,984	1,920,487	1,802,970
Corporate and Other
Segment Reporting Information [Line Items]
Sales and other revenues																	366	(417)	83
Intersegment Revenues																	(715,527)	(651,000)	(653,432)
Revenues																	(715,161)	(651,417)	(653,349)
Refining and Marketing Costs																	(635,530)	(614,714)	(647,603)
Lower of cost or market inventory valuation adjustment																	0	0	0
Operating Expenses																	(72,507)	(28,736)	148
Selling, General and Administrative Expense																	42,372	17,920	14,396
Depreciation, Depletion and Amortization																	10,949	11,895	11,116
Income (loss) from operations																	(60,445)	(37,782)	(31,406)
Income (Loss) from Equity Method Investments																	0	0	(8,541)
Goodwill, Impairment Loss																		0
Asset Impairment Charges																	0
Property, Plant and Equipment, Additions																	19,452	9,080	14,023
Assets	$ 415,032								$ 1,001,368								$ 415,032	$ 1,001,368	$ (21,335)

[1] For 2017, income from operations reflects long-lived asset impairment charges of $23.2 million in the second quarter.

[2] For 2017, income from operations reflects non-cash lower of cost or market inventory valuation charges of $11.8 million and $84.0 million for the first and second quarters, respectively, and a reduction of $111.1 million and $93.4 million for the third and fourth quarters, respectively.

[3] For 2016, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million , respectively, in the second quarter.

[4] For 2016, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $56.1 million and $138.5 million for the first and second quarters, respectively, and increases of $0.3 million for the third quarter and a reduction of $97.7 million for the fourth quarter.

XML

Significant Customers (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenue, Major Customer [Line Items]
Number of significant customers	2
Concentration risk, precentage of total revenues	10.00%
Revenue for reportable segment	$ 14,251,299	$ 10,535,700	$ 13,237,920
Export Sales Risk	0.07064710382
Sinclair Oil Company [Member]
Revenue, Major Customer [Line Items]
Concentration risk, precentage of total revenues	8.00%	9.00%	8.00%
Revenue for reportable segment	$ 1,135,700	$ 927,000	$ 1,104,900
Shell Oil Company [Member]
Revenue, Major Customer [Line Items]
Concentration risk, precentage of total revenues	9.00%	10.00%	9.00%
Revenue for reportable segment	$ 1,317,900	$ 1,048,200	$ 1,252,600
CANADA
Revenue, Major Customer [Line Items]
Export Sales Risk	0.03585778391

XML

Quarterly Information (Unaudited) (Schedule Of Quarterly Information) (Details) - USD ($) $ / shares in Units, shares in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Sales and other revenues	$ 3,992,705,000		$ 3,719,247,000		$ 3,458,864,000		$ 3,080,483,000		$ 2,955,068,000		$ 2,847,270,000		$ 2,714,638,000		$ 2,018,724,000		$ 14,251,299,000	$ 10,535,700,000	$ 13,237,920,000
Operating costs and expenses	3,627,053,000		3,269,967,000		3,337,179,000		3,113,207,000		2,842,776,000		2,722,505,000		3,135,180,000		1,935,126,000		13,347,406,000	10,635,587,000	11,993,567,000
Income (loss) from operations	365,652,000	[1],[2]	449,280,000	[1],[2]	121,685,000	[1],[2]	(32,724,000)	[1],[2]	112,292,000	[3],[4]	124,765,000	[3],[4]	(420,542,000)	[3],[4]	83,598,000	[3],[4]	903,893,000	(99,887,000)	1,244,353,000
Income (loss) before income taxes	371,262,000		446,103,000		106,069,000		(54,571,000)		83,416,000		109,867,000		(430,515,000)		65,698,000		868,863,000	(171,534,000)	1,208,568,000
Net Income (Loss) Attributable to Parent	$ 521,082,000		$ 272,014,000		$ 57,767,000		$ (45,468,000)		$ 53,165,000		$ 74,497,000		$ (409,368,000)		$ 21,253,000		$ 805,395,000	$ (260,453,000)	$ 740,101,000
Net income (loss) per share attributable to HollyFrontier stockholders - basic (in dollars per share)	$ 2.94		$ 1.53		$ 0.33		$ (0.26)		$ 0.30		$ 0.42		$ (2.33)		$ 0.12		$ 4.54	$ (1.48)	$ 3.91
Net income (loss) per share attributable to HollyFrontier stockholders - diluted (in dollars per share)	2.92		1.53		0.33		(0.26)		0.30		0.42		(2.33)		0.12		4.52	(1.48)	$ 3.90
Dividends per common share (in dollars per share)	$ 0.33		$ 0.33		$ 0.33		$ 0.33		$ 0.33		$ 0.33		$ 0.33		$ 0.33		$ 1.32	$ 1.32
Basic	176,265		176,149		176,147		176,210		175,936		175,871		175,865		176,737		176,174	176,101	188,731
Diluted	177,457		176,530		176,302		176,210		176,137		175,993		175,865		176,784		177,196	176,101	188,940
Lower of cost or market inventory valuation adjustment					$ (84,000,000)		$ (11,800,000)				$ 300,000						$ (108,685,000)	$ (291,938,000)	$ 226,979,000
Lower of cost or market inventory valuation adjustment	$ 93,400,000		$ (111,100,000)						$ (97,700,000)				$ 138,500,000		$ 56,100,000		(108,685,000)	(291,938,000)	226,979,000
Asset Impairment Charges					23,200,000												19,247,000	654,084,000	0
Goodwill, Impaired, Accumulated Impairment Loss	309,318,000								309,318,000								309,318,000	309,318,000
Impairment of Long-Lived Assets Held-for-use					$ 19,200,000												344,800,000	0	0
Refining
Condensed Financial Statements, Captions [Line Items]
Sales and other revenues																	12,579,672,000	10,002,831,000	12,677,901,000
Income (loss) from operations																	597,773,000	(332,748,000)	1,036,109,000
Lower of cost or market inventory valuation adjustment																	(107,479,000)	(287,848,000)	$ 225,736,000
Asset Impairment Charges																	19,247,000
Goodwill, Impaired, Accumulated Impairment Loss	$ 309,318,000								$ 309,318,000								$ 309,318,000	$ 309,318,000

[1] For 2017, income from operations reflects long-lived asset impairment charges of $23.2 million in the second quarter.

[2] For 2017, income from operations reflects non-cash lower of cost or market inventory valuation charges of $11.8 million and $84.0 million for the first and second quarters, respectively, and a reduction of $111.1 million and $93.4 million for the third and fourth quarters, respectively.

[3] For 2016, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million , respectively, in the second quarter.

[4] For 2016, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $56.1 million and $138.5 million for the first and second quarters, respectively, and increases of $0.3 million for the third quarter and a reduction of $97.7 million for the fourth quarter.

XML

Label	Element	Value
Osage Pipeline [Member] [Member]
Equity Method Investment, Ownership Percentage	us-gaap_EquityMethodInvestmentOwnershipPercentage	50.00%
Cheyenne [Member]
Equity Method Investment, Ownership Percentage	us-gaap_EquityMethodInvestmentOwnershipPercentage	50.00%