Edgar Filing: HollyFrontier Corp

HFC 12-31-2013 10K

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, 2013



¨	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. ý

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



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

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 28, 2013, 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 $7.9 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.)

198,971,030 shares of Common Stock, par value $.01 per share, were outstanding on February 21, 2014.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 14, 2014, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, are incorporated by reference in Part III.

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TABLE OF CONTENTS



Item	Page

PART I

Forward-Looking Statements	3

Definitions	4

1 and 2. Business and properties	6
1A. Risk Factors	21
1B. Unresolved staff comments	30
3. Legal proceedings	30
4. Mine safety disclosures	31

PART II

5. Market for Registrant's common equity, related stockholder matters and issuer purchases of equity securities	32
6. Selected financial data	33
7. Management's discussion and analysis of financial condition and results of operations	34
7A. Quantitative and qualitative disclosures about market risk	50

Reconciliations to amounts reported under generally accepted accounting principles	50

8. Financial statements and supplementary data	54
9. Changes in and disagreements with accountants on accounting and financial disclosure	100
9A. Controls and procedures	100
9B. Other information	100

PART III

10. Directors, executive officers and corporate governance	100
11. Executive compensation	100
12. Security ownership of certain beneficial owners and management and related stockholder matters	100
13. Certain relationships and related transactions, and director independence	101
14. Principal accounting fees and services	101

PART IV

15. Exhibits, financial statement schedules	101

Signatures	102

Index to exhibits	104

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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. 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. 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.

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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.

“Biodiesel” means a 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 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.

“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.

“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.

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“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.

“Refinery gross margin” means the difference between average net sales price and average product costs per produced barrel of refined products 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.

“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.

“WCS” means Western Canada Select crude oil and is made up of Canadian heavy conventional and bitumen crude oils blended with sweet synthetic and condensate diluents.

“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.

“WTS” means West Texas Sour, a medium sour crude oil.

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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 merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

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 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 Vice President, Investor Relations at the above address. A direct link to our SEC filings is available on our website under the Investor Relations tab. Also available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, Nominating / Corporate Governance Committee Charter, Environmental, Health, Safety, and Public Policy Committee Charter and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. Our Code of Business Conduct and Ethics applies to all of our officers, employees and directors, including our principal executive officer, principal financial officer and principal accounting officer. Our common stock is traded on the New York Stock Exchange under the trading symbol “HFC.”

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by HollyFrontier's post-closing board of directors, Frontier merged with and into HollyFrontier, and HollyFrontier continued as the surviving corporation. This merger combined the legacy Frontier refinery operations consisting of refineries in El Dorado, Kansas (the “El Dorado Refinery”) and Cheyenne, Wyoming (the “Cheyenne Refinery”) with Holly’s legacy refinery operations to form HollyFrontier. The aggregate equity consideration paid in connection with the merger was $3.7 billion.

On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the "Tulsa West facility") from an affiliate of Sunoco, Inc. ("Sunoco") for $157.8 million. On December 1, 2009, we acquired a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company ("Sinclair") also located in Tulsa, Oklahoma (the "Tulsa East facility") for $183.3 million. We have integrated certain operations of the Tulsa West and East facilities (collectively, the "Tulsa Refineries"). This resulted in the Tulsa Refineries having an integrated crude processing rate of 125,000 BPSD.

HEP, a consolidated variable interest entity ("VIE") as defined under U.S. generally accepted accounting principles ("GAAP"), made several acquisitions between 2010 and 2012. Information on these acquisitions can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”

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As of December 31, 2013, we:

•

owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two refinery facilities located in Tulsa, Oklahoma, 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 NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New Mexico;


•	owned a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur, Texas; and

•

owned a 39% interest in HEP, a consolidated VIE, which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”), and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt. The HEP segment involves all of the operations of HEP. The financial information about our segments is discussed in Note 20 “Segment Information” in the Notes to Consolidated Financial Statements.

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 443,000 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. For 2013, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 50%, 33%, 5% and 2%, respectively, of our total refinery sales volumes.

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 effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.



	Years Ended December 31,
	2013		2012		2011 ⁽¹⁰⁾
Consolidated
Crude charge (BPD) ⁽¹⁾	387,520		415,210		315,000
Refinery throughput (BPD) ⁽²⁾	424,780		453,740		340,200
Refinery production (BPD) ⁽³⁾	413,820		442,730		331,890
Sales of produced refined products (BPD)	410,730		431,060		332,720
Sales of refined products (BPD) ⁽⁴⁾	446,390		443,620		340,630
Refinery utilization ⁽⁵⁾	87.5	%	93.7	%	89.9	%

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	Years Ended December 31,
	2013			2012			2011 ⁽¹⁰⁾
Consolidated
Average per produced barrel ⁽⁶⁾
Net sales	$	115.60		$	119.48		$	118.82
Cost of products ⁽⁷⁾	99.61			94.59			98.18
Refinery gross margin	15.99			24.89			20.64
Refinery operating expenses ⁽⁸⁾	6.15			5.49			5.36
Net operating margin	$	9.84		$	19.40		$	15.28

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.95		$	5.22		$	5.24

Feedstocks:
Sweet crude oil	52		%	51		%	56		%
Sour crude oil	21		%	22		%	23		%
Heavy sour crude oil	17		%	17		%	12		%
Black wax crude oil	2		%	2		%	2		%
Other feedstocks and blends	8		%	8		%	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)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.


(4)	Includes refined products purchased for resale.


(5)	Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier.


(6)	Represents average per barrel amount for produced refined products 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.


(7)	Transportation, terminal and refinery storage costs billed from HEP are included in cost of products.


(8)	Represents operating expenses of our refineries, exclusive of depreciation and amortization and pension settlement costs.


(9)	Represents refinery operating expenses, exclusive of depreciation and amortization and pension settlement costs, divided by refinery throughput.


(10)	Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the year ended December 31, 2011.

Principal Products and Customers

Set forth below is information regarding our principal products.



	Years Ended December 31,
	2013		2012		2011
Consolidated
Sales of produced refined products:
Gasolines	50	%	50	%	48	%
Diesel fuels	33	%	31	%	32	%
Jet fuels	5	%	6	%	5	%
Fuel oil	2	%	2	%	2	%
Asphalt	3	%	3	%	4	%
Lubricants	2	%	3	%	3	%
Gas oil / intermediates	—	%	—	%	2	%
LPG and other	5	%	5	%	4	%
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.

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We have several significant customers, of which one accounted for more than 10% of our business in 2013. For the year ended December 31, 2013, Sinclair accounted for $2,134.3 million, or 11%, of our revenues. 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 22 “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 Tulsa West and East refinery facilities are both located in Tulsa, Oklahoma. In 2011, we integrated certain refining processes of the Tulsa Refineries which effectively provides us with a highly complex refining operation having a combined crude processing rate of approximately 125,000 barrels per stream day. For 2013, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 47%, 31%, 8% and 4%, respectively, of our Mid-Continent sales volumes.

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



	Years Ended December 31,
	2013			2012			2011 ⁽¹⁰⁾
Mid-Continent Region (El Dorado and Tulsa Refineries)
Crude charge (BPD) ⁽¹⁾	234,930			248,360			183,070
Refinery throughput (BPD) ⁽²⁾	257,030			269,760			194,310
Refinery production (BPD) ⁽³⁾	251,470			263,310			188,760
Sales of produced refined products (BPD)	247,030			254,350			188,020
Sales of refined products (BPD) ⁽⁴⁾	269,790			258,020			190,340
Refinery utilization ⁽⁵⁾	90.4		%	95.5		%	94.8		%

Average per produced barrel ⁽⁶⁾
Net sales	$	115.63		$	119.19		$	119.51
Cost of products ⁽⁷⁾	99.35			95.77			99.92
Refinery gross margin	16.28			23.42			19.59
Refinery operating expenses ⁽⁸⁾	5.50			4.83			5.04
Net operating margin	$	10.78		$	18.59		$	14.55

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.29		$	4.55		$	4.88

Feedstocks:
Sweet crude oil	69		%	70		%	82		%
Sour crude oil	6		%	8		%	4		%
Heavy sour crude oil	16		%	14		%	8		%
Other feedstocks and blends	9		%	8		%	6		%
Total	100		%	100		%	100		%

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

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. Supporting infrastructure includes maintenance shops, warehouses, office buildings, a laboratory, utility facilities, and a wastewater plant (“Supporting Infrastructure”) and logistics assets owned by HEP, which includes approximately 3.6 million barrels of tankage, a truck sales terminal, and a propane terminal. The facility typically processes approximately 135,000 BPSD of crude oil with the capability to handle a significant volume of heavy sour crudes.

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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, catalytic reforming, 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. Tulsa West facility's Supporting Infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains All American Pipeline, L.P. (“Plains”).

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. The Tulsa East facility's Supporting Infrastructure includes approximately 3.4 million barrels of tankage owned by HEP.

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.

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. Although our Gulf Coast competitors typically have lower production costs because of economies of scale, we believe that our competitors' higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries.

For the year ended December 31, 2013, sales to Shell Oil Products US (“Shell”) represented approximately 27% of the El Dorado Refinery's total sales and 9% of our total consolidated sales. We have an offtake agreement with Shell under which Shell purchases gasoline, diesel and jet fuel production of the El Dorado Refinery at market-based prices through the end of 2014 primarily to support its branded and unbranded marketing network. We market gasoline and diesel primarily in Denver and throughout the Plains States.

The Tulsa Refineries primarily 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.

In conjunction with our acquisition of the Tulsa East facility in 2009, we entered a five-year offtake agreement through November 2014 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, 2013, sales to Sinclair represented approximately 36% of the Tulsa Refineries' total sales and 11% 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.

Our Tulsa West facility also produces specialty lubricant products sold in both commercial and specialty markets throughout North America and to customers with operations in Central America and South America. The specialty lubricant products are high value products that provide a significantly higher margin contribution to the refinery. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural products are formulated as supplemental carriers for herbicides and as Environmental Protection Agency (“EPA”) registered pesticide oils, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive and candle-making markets. Our production represents approximately 6% of paraffinic oil capacity and 13% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.

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Principal Products

Set forth below is information regarding the principal products produced at our El Dorado and Tulsa Refineries:



	Years Ended December 31,
	2013		2012		2011
Mid-Continent Region (El Dorado and Tulsa Refineries)
Sales of produced refined products:
Gasolines	47	%	48	%	44	%
Diesel fuels	31	%	29	%	32	%
Jet fuels	8	%	9	%	7	%
Fuel oil	1	%	1	%	—	%
Asphalt	3	%	2	%	4	%
Lubricants	4	%	5	%	6	%
Gas oil / intermediates	—	%	—	%	3	%
LPG and other	6	%	6	%	4	%
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 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, Gulf of Mexico, Canadian and other foreign 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 or to our Navajo Refinery.

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, naptha and light cycle oil are purchased from other refiners for use at our refineries.

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. For 2013, gasoline and diesel fuel (excluding volumes purchased for resale) represented 51% and 39%, respectively, of our Southwest sales volumes.

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



	Years Ended December 31,
	2013			2012			2011 ⁽¹⁰⁾
Southwest Region (Navajo Refinery)
Crude charge (BPD) ⁽¹⁾	87,910			93,830			83,700
Refinery throughput (BPD) ⁽²⁾	97,310			103,120			93,260
Refinery production (BPD) ⁽³⁾	94,490			100,810			91,810
Sales of produced refined products (BPD)	94,830			99,160			93,950
Sales of refined products (BPD) ⁽⁴⁾	104,320			104,620			98,540
Refinery utilization ⁽⁵⁾	87.9		%	93.8		%	83.7		%

Average per produced barrel ⁽⁶⁾
Net sales	$	117.79		$	122.62		$	118.76
Cost of products ⁽⁷⁾	103.88			95.70			98.40
Refinery gross margin	13.91			26.92			20.36
Refinery operating expenses ⁽⁸⁾	6.04			6.07			5.44
Net operating margin	$	7.87		$	20.85		$	14.92

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.89		$	5.84		$	5.48

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	Years Ended December 31,
	2013		2012		2011 ⁽¹⁰⁾
Southwest Region (Navajo Refinery)
Feedstocks:
Sweet crude oil	8	%	2	%	3	%
Sour crude oil	72	%	77	%	75	%
Heavy sour crude oil	11	%	12	%	11	%
Other feedstocks and blends	9	%	9	%	11	%
Total	100	%	100	%	100	%

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

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. Supporting Infrastructure includes approximately 2.0 million barrels of feedstock and product tankage, of which 0.3 million barrels of tankage are owned by HEP.

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. Supporting Infrastructure includes 1.1 million barrels of feedstock and product tankage of which 0.2 million barrels of tankage are owned by HEP. 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, which has historically experienced a high growth rate, 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 El Paso, Texas; Tucson, Arizona; and Artesia and Moriarty, New Mexico.

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 EnCana Corp.), Valero, Alon and Western Refining. 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, Western Refining, Alon and WRB.

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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 2017, and HEP has options to renew for two ten-year periods. 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 Western Refining.

Principal Products

Set forth below is information regarding the principal products produced at our Navajo Refinery:



	Years Ended December 31,
	2013		2012		2011
Southwest Region (Navajo Refinery)
Sales of produced refined products:
Gasolines	51	%	51	%	52	%
Diesel fuels	39	%	38	%	34	%
Jet fuels	—	%	—	%	1	%
Fuel oil	6	%	6	%	6	%
Asphalt	1	%	2	%	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, our tank trucks and through third-party crude oil pipeline systems for delivery to the Navajo Refinery.

The Navajo Refinery also has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP's Roadrunner Pipeline that connects to Centurion Pipeline L.P. and to various pipelines and tank facilities located at Cushing, Oklahoma. In 2010, the Navajo Refinery began processing heavy sour crude oil transported from Cushing through these pipelines.

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 Refinery has a crude oil processing capacity of 52,000 barrels per stream day and the Woods Cross Refinery has a crude oil capacity of 31,000 barrels per stream day. 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. For 2013, gasoline and diesel fuel (excluding volumes purchased for resale) represented 56% and 30%, respectively, of our Rocky Mountain sales volumes.

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



	Years Ended December 31,
	2013			2012			2011 ⁽¹⁰⁾
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
Crude charge (BPD) ⁽¹⁾	64,680			73,020			48,230
Refinery throughput (BPD) ⁽²⁾	70,440			80,860			52,630
Refinery production (BPD) ⁽³⁾	67,860			78,610			51,320
Sales of produced refined products (BPD)	68,870			77,550			50,750
Sales of refined products (BPD) ⁽⁴⁾	72,280			80,980			51,750
Refinery utilization ⁽⁵⁾	77.9		%	88.0		%	84.3		%

Average per produced barrel ⁽⁶⁾
Net sales	$	112.49		$	116.44		$	116.37
Cost of products ⁽⁷⁾	94.63			89.29			91.33
Refinery gross margin	17.86			27.15			25.04
Refinery operating expenses ⁽⁸⁾	8.65			6.91			6.41
Net operating margin	$	9.21		$	20.24		$	18.63

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	8.46		$	6.63		$	6.18

Feedstocks:
Sweet crude oil	43		%	47		%	52		%
Sour crude oil	1		%	1		%	1		%
Heavy sour crude oil	34		%	31		%	24		%
Black wax crude oil	14		%	11		%	15		%
Other feedstocks and blends	8		%	10		%	8		%
Total	100		%	100		%	100		%

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

The Cheyenne Refinery facility is located on a 255-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, coking, FCCU, 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. Supporting Infrastructure includes approximately 1.9 million barrels of feedstock and product tankage owned by HEP.

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. Supporting Infrastructure includes approximately 1.5 million barrels of feedstock and product tankage, of which 0.2 million barrels of tankage are owned by HEP. The facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 31,000 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.

We are expanding the Woods Cross refinery to a planned capacity of 45,000 BPSD at an anticipated cost of approximately $300.0 million. On November 18, 2013, the Utah Division of Air Quality issued a revised air quality permit (the “Approval Order”) authorizing the expansion. On December 18, 2013, two local environmental groups filed an administrative appeal challenging the issuance of the Approval Order and seeking a stay of the Approval Order. The matter is now pending before an administrative law judge of the Utah Department of Environmental Quality. The expansion is expected to be completed in the fourth quarter of 2015. The expansion scope includes the relocation / revamp of crude, fluid catalytic cracking, and polymerization units as well an expansion of the diesel hydrotreater. The expansion, and expected completion timeline and cost, are subject to the Woods Cross refinery successfully obtaining the Approval Order.

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In conjunction with the expansion, we signed a 10-year, 20,000 BPD crude oil supply agreement with Newfield Exploration Company. This agreement, which commences upon completion of the expansion, will supply black and yellow wax crude oil produced in the nearby Uinta Basin to the Woods Cross Refinery. Upon completion of this expansion, the Woods Cross Refinery's capacity to process waxy crude is expected to double to approximately 24,000 BPD.

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 from the truck rack at the refinery, thus eliminating transportation costs. Pipeline shipments from the Cheyenne Refinery are on 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.

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, Tesoro, 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 150,000 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 Tesoro Logistics Northwest Pipelines LLC (“Tesoro 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 Tesoro 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.

Principal Products

Set forth below is information regarding the principal products produced at our Cheyenne and Woods Cross Refineries:



	Years Ended December 31,
	2013		2012		2011
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
Sales of produced refined products:
Gasolines	56	%	55	%	56	%
Diesel fuels	30	%	32	%	31	%
Jet fuels	1	%	—	%	1	%
Fuel oil	1	%	2	%	1	%
Asphalt	5	%	5	%	6	%
LPG and other	7	%	6	%	5	%
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 Kinder Morgan, Plains All American Pipeline 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 that originate in Canada, Wyoming and Colorado. We also receive crude oil via the SLC Pipeline, a joint venture common carrier pipeline in which HEP owns a 25% interest. Supplies of black wax crude oil are shipped via truck.

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NK Asphalt Partners

We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. We have three manufacturing facilities located in Glendale, Arizona; Albuquerque, New Mexico; and Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity 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 products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.

Other Assets

We own a 50% joint venture interest in Sabine Biofuels II, LLC, a 30 million gallon per year biodiesel production facility located near Port Arthur, Texas.

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 was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States.

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

HEP's recent acquisitions (2009 through present) are summarized below:

UNEV Interest Transaction

On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in cash and 1.0 million HEP common units. UNEV owns the UNEV Pipeline, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada together with terminal facilities in Cedar City, Utah and North Las Vegas. The UNEV Pipeline was completed in late 2011 and became operational during the first quarter of 2012.

Legacy Frontier Pipeline and Tankage Asset Transaction

On November 9, 2011, HEP acquired from us certain tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries. We received non-cash consideration consisting of promissory notes with an aggregate principal amount of $150.0 million and 3.8 million HEP common units.

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, HEP acquired from us certain storage assets for $93.0 million, consisting of hydrocarbon storage tanks having approximately 2.0 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa East facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, HEP acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at what is now our Tulsa East facility for $79.2 million.

Roadrunner / Beeson Pipelines Transaction

Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery Lovington facility to a terminus of Centurion Pipeline L.P.'s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects HEP's New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).

Tulsa West Loading Racks Transaction

On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa West facility for $17.5 million.

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Lovington-Artesia Pipeline Transaction

On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from our Navajo Refinery's crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery located in Artesia, New Mexico.

SLC Pipeline Joint Venture Interest

On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. HEP's capitalized joint venture contribution was $25.5 million.

Rio Grande Pipeline Sale

On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35.0 million.

Transportation Agreements

Agreements with HEP

HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2013, these agreements result in minimum annualized payments to HEP of $225.5 million.

Since HEP is a consolidated VIE, our transactions with HEP including the transactions discussed above and fees paid under our transportation agreements with HEP and UNEV, a consolidated subsidiary of HEP, are eliminated and have no impact on our consolidated financial statements.

Agreement with Alon

HEP has a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon 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 Alon under which Alon 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, 2013, HEP's assets include:

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 Alon's Big Spring refinery in Texas to its customers in Texas and Oklahoma;


•	three 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;


•	approximately 970 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery;


•	approximately 10 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 the Tulsa East and Tulsa West facilities; and


•	crude receiving assets located at our Cheyenne Refinery.

Refined Product Terminals and Refinery Tankage


•	four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,300,000 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;

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•	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 Alon'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 (“LACT”) units located at our Cheyenne Refinery;


•	on-site crude oil tankage at our Tulsa, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity of approximately 1,200,000 barrels; and


•	on-site refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate storage capacity of approximately 8,400,000 barrels.

Additionally, HEP owns a 75% interest in UNEV, which owns the UNEV Pipeline, a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada together with terminal facilities in the Cedar City, Utah and North Las Vegas areas, and a 25% interest in SLC Pipeline LLC, which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

We lease approximately 60,000 square feet for our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires in 2021. 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, 2013, we had 2,662 employees, of which 886 are currently covered by collective bargaining agreements having various expiration dates between 2015 and 2018. We consider our employee relations to be good.

Regulation

Refinery and pipeline operations are subject to numerous federal, state and local laws regulating the discharge of substances into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related facilities, and these permits are subject to revocation, modification and renewal. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, the results of operations, and our capital requirements. We believe that our current operations are in substantial compliance with applicable federal, state, and local environmental laws, regulations, and permits.

Our operations and many of the products we manufacture 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. Additionally, the 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. Subsequent rulemaking authorized by the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years.

Also, we are subject to the EPA's new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations on gasoline that impose reductions in the benzene content of our produced gasoline. Our refineries currently purchase a portion of their benzene credits to meet these requirements. If economically justified, we could implement additional benzene reduction projects to eliminate the need to purchase benzene credits.

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The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 prescribe certain percentages of renewable fuels (e.g., ethanol and biofuels) that, where required, must be blended into our produced gasoline and diesel. Additional changes in fuel standards, tier III standards, to reduce vehicle emissions are expected to be finalized by the end of February 2014. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may, where required, cause us to make substantial capital expenditures and purchase credits at significant cost to enable our refineries to produce products that meet applicable requirements.

Further regulatory requirements have emerged from concerns over the potential climate impacts of certain "greenhouse gases" such as carbon dioxide and methane. In response to a statutory directive, the EPA has promulgated rules requiring the reporting of greenhouse gas emissions. In 2010, the EPA promulgated regulations applying construction and operating permit requirements under the CAA's Prevention of Significant Deterioration and Title V programs to sources with potential greenhouse gas emissions above certain threshold levels. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating greenhouse gas emissions from refineries. Proposals both expanding and limiting the EPA's authority in this area continue to be considered in Congress. Litigation challenging the EPA's authority over greenhouse gas emissions also is pending in federal court. The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) decided in 2012 to uphold the rules, but the U.S. Supreme Court has agreed to review that decision.

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. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.

We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) 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.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including the current and past owner or operator of the disposal site or sites from which there is a release of a “hazardous substance,” as well as persons that disposed of or arranged for the disposal or treatment of the hazardous substances at the site or sites. Under CERCLA, such persons may be subject to joint and several liability for such costs as the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In the course of our historical operations, as well as in our current normal 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 by a government entity or other third party. 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. Under CERCLA, liable parties may seek contribution from other liable parties to share in the costs of cleanup. 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.

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, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of. 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, 2013, we had an accrual of $87.8 million related to such environmental liabilities.

We are and have been the subject of various state, 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.

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Health and environmental legislation and regulations change frequently. We cannot predict what additional 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 that is made up 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.

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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 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, 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.

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. 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.

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:

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•	denial or delay in issuing requisite regulatory approvals and/or permits;


•	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 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.

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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.

Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation 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. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits 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. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of 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 state, 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. 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.

We cannot predict what additional 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. However, new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. The EPA has begun regulating certain emissions of greenhouse gases, or “GHGs,” (including carbon dioxide, methane and nitrous oxides) from large stationary sources like refineries under the authority of the CAA, and it is possible that Congress could pass federal legislation that creates a comprehensive GHG regulatory program, either directly or indirectly, such as via a federal renewal energy standard. Also, new federal or state legislation or regulatory programs that restrict emissions of GHGs in areas where we conduct business could adversely affect demand for our products and our 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. 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. 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.

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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 by Congress could result in increased operating costs and reduced demand for the refined products we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which may require permits for emissions of GHGs from certain large stationary sources. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions were upheld by the D.C. Circuit, but the U.S. Supreme Court has agreed to review that decision in response to petitions by numerous parties. 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. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating GHG emissions from refineries.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. These cap and trade programs generally work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and on an annual basis surrender emission allowances. The number of allowances available for purchase is reduced over time in an effort to achieve the overall GHG emission reduction goal.

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.

In addition, 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, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition and results of operations.

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

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage or destruction of property, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. 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 availability of adequate insurance may be affected by conditions in the insurance market over which we have no control, resulting in the inability to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase or, in some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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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. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

The availability and cost of renewable identification numbers 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 Renewable Fuel Standard 2 (“RFS2”) 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 renewable identification numbers (“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 RFS2. 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 RFS2 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 RFS2 mandates, our financial condition and results of operations could be adversely affected.

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.

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.

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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 material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.

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.

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.

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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.

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. 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. 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.

We currently own a 39% interest in HEP, including the 2% general partner interest. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Arizona, Idaho, Kansas, New Mexico, Oklahoma, Texas, Utah, Washington and Wyoming. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, leasing certain pipeline capacity to Alon, 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 2019 through 2026. 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, 2013.

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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.

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, 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, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, are not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding continued global hostilities or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. 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. Such 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.

We may be unable to pay future regular and/or special 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 regular and/or special 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 of such payments.

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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.

Our debt agreements contain operating and financial restrictions that might 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, investments, indebtedness and dividends; (ii) a prohibition on changes in control and (iii) restrictions on engaging in mergers, consolidations and sales of assets, entering into certain lease obligations, and making certain investments or capital expenditures. If we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the 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. In addition, our obligations under our credit facility are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facility when due, the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.

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Our business may suffer due to a change in the composition of our Board of Directors, or by the 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, 2013, 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 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.

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.

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While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Environmental Matters

We are reporting the following proceedings to comply with SEC regulations which require us to disclose proceedings arising under federal, state 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 consolidated financial position.

Frontier Refining LLC (“FR”), our wholly-owned subsidiary, has undertaken environmental audits at the Cheyenne Refinery regarding compliance with federal and state environmental requirements. By letters dated October 5, 2012, and November 7, 2012, and January 10, 2013, and pursuant to EPA's audit policy to the extent applicable, FR submitted reports to the EPA voluntarily disclosing non-compliance with certain emission limitations, reporting requirements, and provisions of a 2009 federal consent decree. By letters dated October 31, 2012, February 6, 2013, June 21, 2013, July 9, 2013, and July 25, 2013, and pursuant to applicable Wyoming audit statutes, FR submitted environmental audit reports to the Wyoming Department of Environmental Quality (“WDEQ”) voluntarily disclosing non-compliance with certain notification, reporting, and other provisions of the refinery's state air permit and other environmental regulatory requirements. Additional self-disclosures and follow-up correspondence are anticipated as the audit activities are completed. No further action has been taken by either agency at this time. The Cheyenne Refinery also has four outstanding Notices of Violations issued in 2010, 2011 and 2013 that are subject to ongoing settlement negotiations with the WDEQ. Additional air and other environmental audits for the Cheyenne Refinery are scheduled for 2014.

Between November 2010 and February 2012, certain of our subsidiaries submitted multiple reports to the EPA to voluntarily disclose non-compliance with fuels regulations at the Cheyenne, El Dorado, Navajo, Tulsa and Woods Cross refineries and at the Cedar City, Utah and Henderson, Colorado terminals. The EPA has requested additional information regarding certain of these reports, and our subsidiaries have complied with all requests received to date.

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.

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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
2013
Fourth quarter	$	50.63	$	39.65	$	0.800	230,186,600
Third quarter	$	47.21	$	38.98	$	0.800	174,416,900
Second quarter	$	52.87	$	39.96	$	0.800	229,246,900
First quarter	$	59.20	$	42.76	$	0.800	217,439,700

2012
Fourth quarter	$	47.39	$	36.22	$	0.700	161,950,900
Third quarter	$	42.33	$	33.92	$	1.150	171,023,300
Second quarter	$	36.10	$	28.05	$	0.650	232,551,400
First quarter	$	36.45	$	23.96	$	0.600	230,380,300

In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an additional $350 million repurchase program that authorizes 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, corporate, regulatory and other relevant considerations. These programs may be discontinued at any time by the Board of Directors. The following table includes repurchases made under this program during the fourth quarter of 2013.



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 2013	423,800	$	42.80	423,800	$	313,327,358
November 2013	40,000	$	43.90	40,000	$	311,571,488
December 2013 ⁽¹⁾	475,000	$	47.83	—	$	311,571,488
Total for October to December 2013	938,800			463,800

(1) The December 2013 shares repurchased were not purchased under our approved stock repurchase program, but rather pursuant to separate authority from our Board of Directors. These repurchases were made in the open market.

As of February 11, 2014, we had approximately 127,580 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. Our credit agreement and senior notes limit the payment of dividends. See Note 12 “Debt” in the Notes to Consolidated Financial Statements.

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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,
	2013			2012			2011			2010			2009
	(In thousands, except per share data)
FINANCIAL DATA ⁽¹⁾
For the period
Sales and other revenues	$	20,160,560		$	20,090,724		$	15,439,528		$	8,322,929		$	4,834,268
Income from continuing operations before income taxes	1,159,399			2,787,995			1,641,695			192,363			43,803
Income tax provision	391,576			1,027,962			581,991			59,312			7,460
Income from continuing operations	767,823			1,760,033			1,059,704			133,051			36,343
Income from discontinued operations, net of taxes ⁽²⁾	—			—			—			—			16,926
Net income	767,823			1,760,033			1,059,704			133,051			53,269
Less net income attributable to noncontrolling interest	31,981			32,861			36,307			29,087			33,736
Net income attributable to HollyFrontier stockholders	$	735,842		$	1,727,172		$	1,023,397		$	103,964		$	19,533
Earnings per share attributable to HollyFrontier stockholders - basic	$	3.66		$	8.41		$	6.46		$	0.98		$	0.20
Earnings per share attributable to HollyFrontier stockholders - diluted	$	3.64		$	8.38		$	6.42		$	0.97		$	0.20
Cash dividends declared per common share	$	3.20		$	3.10		$	1.34		$	0.30		$	0.30
Average number of common shares outstanding:
Basic	200,419			204,379			157,948			106,436			100,836
Diluted	201,234			205,274			158,756			107,218			101,206

Net cash provided by operating activities	$	869,174		$	1,662,687		$	1,338,391		$	283,255		$	211,545
Net cash provided by (used for) investing activities	$	(526,735	)	$	(711,104	)	$	228,494		$	(213,232	)	$	(534,603	)
Net cash provided by (used for) financing activities	$	(1,160,035	)	$	(772,788	)	$	(217,082	)	$	34,482		$	406,849

At end of period
Cash, cash equivalents and investments in marketable securities	$	1,665,263		$	2,393,401		$	1,840,610		$	230,444		$	125,819
Working capital	$	2,221,954		$	2,815,821		$	2,030,063		$	313,580		$	257,899
Total assets	$	10,056,739		$	10,328,997		$	9,576,243		$	3,049,951		$	2,766,318
Total debt⁽³⁾	$	997,519		$	1,336,238		$	1,214,742		$	810,561		$	707,458
Total equity	$	6,609,398		$	6,642,658		$	5,835,900		$	1,288,139		$	1,207,781


(1)	We merged with Frontier on July 1, 2011. Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011. See “Company Overview” under Items 1 and 2, “Business and Properties” for information on our merger.


(2)	On December 1, 2009, HEP sold its 70% interest in Rio Grande. Results of operations of Rio Grande are presented in discontinued operations.


(3)	Includes total HEP debt of $807.6 million, $864.7 million, $525.9 million, $482.3 million and $379.2 million, respectively, which is non-recourse to HollyFrontier.

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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.

We merged with Frontier on July 1, 2011. Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

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 crude oil processing capacity of 443,000 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, a petroleum refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross Refinery).

For the year ended December 31, 2013, net income attributable to HollyFrontier stockholders was $735.8 million compared to $1,727.2 million for the year ended December 31, 2012.

Overall gross refining margins per produced product sold decreased 36% over the year ended December 31, 2012 due principally to significant contraction in WTI to Brent crude differentials as well as lower discounts on heavy sour crudes purchased during the second and third quarters of 2013.

Net income for the year ended December 31, 2013 reflects pension settlement and debt extinguishment charges of $39.5 million and $22.1 million, respectively. Also affecting current year net income were the effects of planned turnarounds at our El Dorado, Tulsa and Navajo Refineries as well as unplanned downtime incurred at each of our El Dorado and Cheyenne Refineries due to FCC unit issues during the second quarter of 2013.

Our financial and operating results additionally reflect lower crude oil throughput rates for the Southwest region, which averaged 74,370 BPD for the fourth quarter of 2013 compared to 99,610 BPD for the same period last year, as a result of waste water constraints at our Navajo Refinery during late 2013. This matter was resolved in January 2014 and throughput rates have since returned to planned levels.

OUTLOOK

Our profitability is affected by the spread, or differential, between the market prices for crude oil on the world market (which is based on the price for Brent, North Sea Crude) and the price for inland U.S. crude oil (which is based on the price for WTI). This differential constantly changes and at times can be volatile. While we have experienced wide differentials (with Brent prices in excess of WTI prices) in recent years, which have significantly enhanced our profitability, the differential between Brent and WTI narrowed significantly during the second half of 2013 - averaging approximately one-half of the differential experienced during 2012. Differentials are likely to continue to be volatile in the near term. However, we expect the Brent to WTI differential to rebound upon completion of additional northern tier pipeline capacity into Cushing, Oklahoma, which we believe will create a surplus of light sweet crude oil on the U.S. Gulf Coast. Ultimately, we believe pipeline tariffs from Cushing to the Gulf Coast plus marine transportation costs to transport product from the Gulf Coast to alternative markets will set the inland - coastal differential.

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Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS2 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. As of December 2013, we are purchasing RINs in order to meet approximately half of our renewable fuel requirements. 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 due to real or perceived future shortages in RINs. As a result, we expect to continue to experience higher than historical costs to comply with the renewable fuel mandate. In the wholesale markets we serve, we are seeing price adjustments to indicate that the cost of RINs is being largely borne by the consumer at the pump. However, we continue to use various approaches to mitigate our exposure to the increasing cost of RINs, which include additional renewable fuel blending, shifts in our refined product slate and changes in the way we conduct marketing operations. We cannot predict with certainty whether and to what extent we will be successful in mitigating our exposure to increased RINs costs, and anticipate that increased compliance costs may negatively impact our future results of operations. In 2013, our ethanol RINs purchases from third parties totaled approximately 215 million RINs.

A more detailed discussion of our financial and operating results for the years ended December 31, 2013, 2012 and 2011 is presented in the following sections.

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Results Of Operations

Financial Data



	Years Ended December 31,
	2013			2012			2011 ⁽¹⁾
	(In thousands, except per share data)
Sales and other revenues	$	20,160,560		$	20,090,724		$	15,439,528
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	17,392,227			15,840,643			12,680,078
Operating expenses (exclusive of depreciation and amortization)	1,090,850			994,966			748,081
General and administrative expenses (exclusive of depreciation and amortization)	127,963			128,101			120,114
Depreciation and amortization	303,446			242,868			159,707
Total operating costs and expenses	18,914,486			17,206,578			13,707,980
Income from operations	1,246,074			2,884,146			1,731,548
Other income (expense):
Earnings (loss) of equity method investments	(2,072		)	2,923			2,300
Interest income	5,556			4,786			1,284
Interest expense	(68,050		)	(104,186		)	(78,323		)
Loss on early extinguishment of debt	(22,109		)	—			—
Gain on sale of marketable securities	—			326			—
Merger transaction costs	—			—			(15,114		)
	(86,675		)	(96,151		)	(89,853		)
Income before income taxes	1,159,399			2,787,995			1,641,695
Income tax provision	391,576			1,027,962			581,991
Net income	767,823			1,760,033			1,059,704
Less net income attributable to noncontrolling interest	31,981			32,861			36,307
Net income attributable to HollyFrontier stockholders	$	735,842		$	1,727,172		$	1,023,397
Earnings per share attributable to HollyFrontier stockholders:
Basic	$	3.66		$	8.41		$	6.46
Diluted	$	3.64		$	8.38		$	6.42
Cash dividends declared per common share	$	3.20		$	3.10		$	1.34
Average number of common shares outstanding:
Basic	200,419			204,379			157,948
Diluted	201,234			205,274			158,756

(1) Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011.

Other Financial Data



	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Net cash provided by operating activities	$	869,174		$	1,662,687		$	1,338,391
Net cash provided by (used for) investing activities	$	(526,735	)	$	(711,104	)	$	228,494
Net cash used for financing activities	$	(1,160,035	)	$	(772,788	)	$	(217,082	)
Capital expenditures	$	425,127		$	335,263		$	374,241
EBITDA ⁽¹⁾	$	1,515,467		$	3,097,402		$	1,842,134

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(1)

Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income 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.

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

Refining 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 effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.



	Years Ended December 31,
	2013			2012			2011 ⁽¹⁰⁾
Consolidated
Crude charge (BPD) ⁽¹⁾	387,520			415,210			315,000
Refinery throughput (BPD) ⁽²⁾	424,780			453,740			340,200
Refinery production (BPD) ⁽³⁾	413,820			442,730			331,890
Sales of produced refined products (BPD)	410,730			431,060			332,720
Sales of refined products (BPD) ⁽⁴⁾	446,390			443,620			340,630
Refinery utilization ⁽⁵⁾	87.5		%	93.7		%	89.9		%

Average per produced barrel ⁽⁶⁾
Net sales	$	115.60		$	119.48		$	118.82
Cost of products ⁽⁷⁾	99.61			94.59			98.18
Refinery gross margin	15.99			24.89			20.64
Refinery operating expenses ⁽⁸⁾	6.15			5.49			5.36
Net operating margin	$	9.84		$	19.40		$	15.28

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.95		$	5.22		$	5.24


(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)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.


(4)	Includes refined products purchased for resale.


(5)	Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier.


(6)	Represents average per barrel amount for produced refined products 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.


(7)	Transportation, terminal and refinery storage costs billed from HEP are included in cost of products.


(8)	Represents operating expenses of our refineries, exclusive of depreciation and amortization and pension settlement costs.


(9)	Represents refinery operating expenses, exclusive of depreciation and amortization and pension settlement costs, divided by refinery throughput.


(10)	Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the year ended December 31, 2011.

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Results of Operations – Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Summary

Net income attributable to HollyFrontier stockholders for the year ended December 31, 2013 was $735.8 million ($3.66 per basic and $3.64 per diluted share), a $991.4 million decrease compared to $1,727.2 million ($8.41 per basic and $8.38 per diluted share) for the year ended December 31, 2012. Net income decreased due principally to a year-over-year decrease in refining margins, refinery downtime and pension settlement and debt extinguishment charges. Refinery gross margins for the year ended December 31, 2013 decreased to $15.99 per produced barrel from $24.89 for the year ended December 31, 2012.

Sales and Other Revenues

Sales and other revenues increased slightly from $20,090.7 million for the year ended December 31, 2012 to $20,160.6 million for the year ended December 31, 2013 due to higher refined product sales volumes, partially offset by a decrease in year-over-year sales prices. The average sales price we received per produced barrel sold decreased 3% from $119.48 for the year ended December 31, 2012 to $115.60 for the year ended December 31, 2013. Refined product sales volumes for the current period reflect higher volumes of purchased products, comprising 8% of total refined products sales compared to 3% for the year ended December 31, 2012 due to a decrease in refinery production and corresponding sales volumes of produced product as a result of planned turnaround and maintenance projects at our refineries and other unplanned refinery outages during the current year. Sales and other revenues for the years ended December 31, 2013 and 2012 include $53.4 million and $47.6 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 10% from $15,840.6 million for the year ended December 31, 2012 to $17,392.2 million for the year ended December 31, 2013, due principally to higher refined product sales volumes and crude costs for the current year. The sales volume increase is attributable to higher sales volumes of purchased products caused in part, by planned turnaround projects and unplanned refinery outages during the year ended December 31, 2013. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place increased 5% from $94.59 for the year ended December 31, 2012 to $99.61 for the year ended December 31, 2013.

Gross Refinery Margins

Gross refinery margin per produced barrel decreased 36% from $24.89 for the year ended December 31, 2012 to $15.99 for the year ended December 31, 2013. This was due to a decrease in average per barrel sales prices for refined products sold combined with increased crude oil and feedstock prices for the current year. Gross refinery margin does not include the effects of 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, increased 10% from $995.0 million for the year ended December 31, 2012 to $1,090.9 million for the year ended December 31, 2013 due principally to higher repair and maintenance and fuel costs during the current year period and $31.7 million in pension settlement costs, partially offset by a decrease in environmental remediation costs. For the years ended December 31, 2013 and 2012, operating expenses include $95.7 million and $88.9 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses

General and administrative expenses were $128.0 million and $128.1 million for the years ended December 31, 2013 and 2012, respectively. For the years ended December 31, 2013 and 2012, general and administrative expenses include $9.4 million and $5.3 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 25% from $242.9 million for the year ended December 31, 2012 to $303.4 million for the year ended December 31, 2013. The increase was due principally to depreciation and amortization attributable to capitalized improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2013 and 2012, depreciation and amortization expenses include $64.7 million and $57.8 million, respectively, in costs attributable to HEP operations.

Interest Income

Interest income for the year ended December 31, 2013 was $5.6 million compared to $4.8 million for the year ended December 31, 2012. This increase was due to interest received on increased investments in marketable debt securities during the current year period.

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Interest Expense

Interest expense was $68.1 million for the year ended December 31, 2013 compared to $104.2 million for the year ended December 31, 2012. This decrease was due to lower year-over-year debt levels principally as a result of the redemption of our $286.8 million 9.875% senior notes in June 2013 and $200 million 8.5% senior notes in September 2012. For the years ended December 31, 2013 and 2012, interest expense included $46.8 million and $57.2 million, respectively, in interest costs attributable to HEP operations.

Loss on Early Extinguishment of Debt

In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017 at a redemption cost of $301.0 million, at which time we recognized a $22.1 million early extinguishment loss consisting of a $14.2 million debt redemption premium and an unamortized discount of $7.9 million.

Income Taxes

For the year ended December 31, 2013, we recorded income tax expense of $391.6 million compared to $1,028.0 million for the year ended December 31, 2012. This decrease was due principally to lower pre-tax earnings during the year ended December 31, 2013 compared to the same period of 2012. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 33.8% and 36.9% for the years ended December 31, 2013 and 2012, respectively. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation.

Results of Operations – Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Summary

Net income attributable to HollyFrontier stockholders for the year ended December 31, 2012 was $1,727.2 million ($8.41 per basic and $8.38 per diluted share) a $703.8 million increase compared to $1,023.4 million ($6.46 per basic and $6.42 per diluted share) for the year ended December 31, 2011. Net income increased due principally to greater operating scale following our July 1, 2011 merger and higher refining margins in 2012. Refinery gross margins for the year ended December 31, 2012 increased to $24.89 per produced barrel compared to $20.64 for the year ended December 31, 2011.

Sales and Other Revenues

Sales and other revenues increased 30% from $15,439.5 million for the year ended December 31, 2011 to $20,090.7 million for the year ended December 31, 2012, due principally to the inclusion of sales volumes and related revenues attributable to the El Dorado and Cheyenne Refineries for a full year period and higher sales volumes of refined products produced from the legacy Holly refineries. Additionally, the average sales price we received per produced barrel sold increased 1% from $118.82 for the year ended December 31, 2011 to $119.48 for the year ended December 31, 2012. Sales and other revenues for the years ended December 31, 2012 and 2011, include $47.6 million and $46.4 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 25% from $12,680.1 million for the year ended December 31, 2011 to $15,840.6 million for the year ended December 31, 2012, due principally to the inclusion of sales volumes and related cost of products sold at the El Dorado and Cheyenne Refineries, partially offset by lower crude oil costs for 2012. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place decreased 4% from $98.18 for the year ended December 31, 2011 to $94.59 for the year ended December 31, 2012.

Gross Refinery Margins

Gross refining margin per produced barrel increased 21% from $20.64 for the year ended December 31, 2011 to $24.89 for the year ended December 31, 2012. This is due to the effects of a current year decrease in crude oil and feedstock prices along with slightly higher sales prices received on produced products sold. Gross refinery margin does not include the effects of depreciation or amortization.

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Operating Expenses

Operating expenses, exclusive of depreciation and amortization increased 33% from $748.1 million for the year ended December 31, 2011 to $995.0 million for the year ended December 31, 2012, due principally to the inclusion of the legacy Frontier refinery operations for a full-year period and higher repair and maintenance and environmental remediation costs. In 2012, we increased certain environmental remediation accruals by $46.1 million to reflect revisions to certain cost estimates and the timeframe for which certain environmental remediation and monitoring activities are expected to occur. Also contributing to a much lesser extent were increased payroll costs attributable to the legacy Holly refining operations. For the years ended December 31, 2012 and 2011, operating expenses include $88.9 million and $61.1 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses

General and administrative expenses increased 7% from $120.1 million for the year ended December 31, 2011 to $128.1 million for the year ended December 31, 2012, due principally to higher employee benefit and equity-based compensation costs and increased corporate staffing levels as a result of our July 1, 2011 merger, net of the effects of merger related severance and integration costs incurred during 2011. For the years ended December 31, 2012 and 2011, general and administrative expenses include $5.3 million and $4.3 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 52% from $159.7 million for the year ended December 31, 2011 to $242.9 million for the year ended December 31, 2012. The increase was due principally to depreciation and amortization attributable to the legacy Frontier refinery assets, capitalized improvement projects and HEP's UNEV Pipeline. For the years ended December 31, 2012 and 2011, depreciation and amortization expenses include $57.8 million and $33.3 million, respectively, in costs attributable to HEP operations.

Interest Income

Interest income for the year ended December 31, 2012 was $4.8 million compared to $1.3 million for the year ended December 31, 2011. This increase was due to interest received on our increased cash position and investments in marketable debt securities.

Interest Expense

Interest expense was $104.2 million for the year ended December 31, 2012 compared to $78.3 million for the year ended December 31, 2011. This increase principally reflects interest on the senior notes assumed upon our merger with Frontier. For the years ended December 31, 2012 and 2011, interest expense included $57.2 million and $38.2 million, respectively, in interest costs attributable to HEP operations.

Merger Transaction Costs

For the year ended December 31, 2011, we recognized merger transaction costs of $15.1 million related to our merger with Frontier on July 1, 2011. These costs included legal, advisory and other professional fees that were directly attributable to the merger. There were no such costs incurred for the year ended December 31, 2012.

Income Taxes

For the year ended December 31, 2012, we recorded income tax expense of $1,028.0 million compared to $582.0 million for the year ended December 31, 2011. This increase is due principally to significantly higher pre-tax earnings for the year ended December 31, 2012 compared to the same period of 2011. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 36.9% and 35.5% for the years ended December 31, 2012 and 2011, respectively. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation.

LIQUIDITY AND CAPITAL RESOURCES

HollyFrontier Credit Agreement

We have a $1 billion senior secured credit agreement that matures in July 2016 (the “HollyFrontier Credit Agreement”) and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2013, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $5.2 million under the HollyFrontier Credit Agreement.

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HEP Credit Agreement

HEP has a $650 million senior secured revolving credit facility that matures in November 2018 (the “HEP Credit Agreement”) and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit. At December 31, 2013, HEP was in compliance with all of its covenants, had outstanding borrowings of $363.0 million and no outstanding letters of credit under the HEP Credit Agreement.

Indebtedness under the HEP Credit Agreement bears interest, at their 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 interest rates in effect on HEP’s Credit Agreement borrowings were 2.163% and 2.456% at December 31, 2013 and 2012, respectively.

HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s 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

Our 6.875% senior notes ($150.0 million principal amount maturing November 2018) (the “HollyFrontier Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes.

At any time, following notice to the trustee, that the HollyFrontier Senior Notes are rated investment grade by both Moody's and Standard & Poor's and no default or event of default exists, we are not subject to many of the foregoing covenants (a "Covenant Suspension"). As of December 31, 2013, the HollyFrontier Senior Notes were rated investment grade (BBB-) by Standard & Poor's and also investment grade (Baa3) by Moody's. As a result, we are under the Covenant Suspension pursuant to the terms of the indenture governing the HollyFrontier Senior Notes.

In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017.

HollyFrontier Financing Obligation

We have a financing obligation that relates to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) in October 2009 for $40.0 million. Monthly lease payments are recorded as a reduction in principal over the 15-year lease term ending in 2024.

HEP Senior Notes

HEP’s senior notes consist of the following:


•	8.25% HEP senior notes ($150 million principal amount maturing March 2018)


•	6.5% HEP senior notes ($300 million principal amount maturing March 2020)

The 8.25% and 6.5% HEP senior notes (collectively, 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. On February 12, 2014, HEP announced that it will redeem all of its outstanding 8.25% senior notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% senior notes is scheduled to occur on March 15, 2014. HEP plans to fund the redemption with borrowings under the HEP Credit Agreement.

Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. However, 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 other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

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HEP Common Unit Issuance

In March 2013, HEP closed on a public offering of 1,875,000 of its common units. Additionally, our wholly-owned subsidiary, HollyFrontier Holdings LLC, as a selling unitholder, closed on a public sale of 1,875,000 HEP common units held by it. HEP used net proceeds of $73.4 million to repay indebtedness incurred under its credit facility and for general partnership purposes.

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.

As of December 31, 2013, our cash, cash equivalents and investments in marketable securities totaled $1.7 billion. 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.

We have a Board approved stock repurchase program that authorizes 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, corporate, regulatory and other relevant considerations. This program may be discontinued at any time by the Board of Directors. As of December 31, 2013, we had remaining authorization to repurchase up to $311.6 million under this stock repurchase program.

Cash and cash equivalents decreased $817.6 million for the year ended December 31, 2013. Net cash used for investing and financing activities of $526.7 million and $1,160.0 million, respectively, exceeded net cash provided by operating activities of $869.2 million. Working capital decreased by $593.9 million during the year ended December 31, 2013.

Cash Flows – Operating Activities

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Net cash flows provided by operating activities were $869.2 million for the year ended December 31, 2013 compared to $1,662.7 million for the year ended December 31, 2012, a decrease of $793.5 million. Net income for the year ended December 31, 2013 was $767.8 million, a decrease of $992.2 million compared to $1,760.0 million for the year ended December 31, 2012. Reconciling adjustments to net income consisted of depreciation and amortization, earnings of equity method investments, net of distributions, the write-off of an unamortized discount on the early extinguishment of debt, gain on sale of equity securities, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and loss on settlement of retirement benefit obligations, net of contributions which totaled $430.4 million for the year ended December 31, 2013 compared to $410.7 million for the same period in 2012. Changes in working capital items decreased cash flows by $157.0 million for the year ended December 31, 2013 compared to $398.0 million for the year ended December 31, 2012. Additionally, for the year ended December 31, 2013, refinery turnaround expenditures increased to $193.9 million from $159.7 million for the same period of 2012.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net cash flows provided by operating activities were $1,662.7 million for the year ended December 31, 2012 compared to $1,338.4 million for the year ended December 31, 2011, an increase of $324.3 million. Net income for the year ended December 31, 2012 was $1,760.0 million, an increase of $700.3 million compared to $1,059.7 million for the year ended December 31, 2011. Reconciling adjustments consisting of depreciation and amortization, earnings of equity method investments, net of distributions, gain on sale of equity securities, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and loss on settlement of retirement benefit obligations, net of contributions resulted in an increase to operating cash flows of $433.0 million for the year ended December 31, 2012 compared to $182.3 million for the same period in 2011. Changes in working capital items decreased cash flows by $398.0 million for the year ended December 31, 2012 compared to an increase of $147.3 million for the year ended December 31, 2011. The decrease in working capital items for the year ended December 31, 2012 was due principally to higher inventory levels and a decrease in income taxes payable and accrued liabilities due to timing differences of payments during the fourth quarter of 2012 relative to 2011. Additionally, for the year ended December 31, 2012, refinery turnaround expenditures increased to $159.7 million from $32.0 million for the same period of 2011.

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Cash Flows – Investing Activities and Planned Capital Expenditures

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Net cash flows used for investing activities were $526.7 million for the year ended December 31, 2013 compared to $711.1 million for the year ended December 31, 2012, a decrease of $184.4 million. Cash expenditures for properties, plants and equipment for 2013 increased to $425.1 million from $335.3 million for the same period in 2012. These include HEP capital expenditures of $51.9 million and $44.9 million for the years ended December 31, 2013 and 2012, respectively. In addition, for the year ended December 31, 2013, we received proceeds of $7.8 million from the sale of property and equipment, invested and advanced a net total of $8.7 million to Sabine Biofuels and acquired trucking operations for $11.3 million. For the year ended December 31, 2012, we invested $2.0 million in Sabine Biofuels. Also for the years ended December 31, 2013 and 2012, we invested $935.5 million and $671.6 million, respectively, in marketable securities and received proceeds of $846.1 million and $297.7 million, respectively, from the sale or maturity of marketable securities.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net cash flows used for investing activities were $711.1 million for the year ended December 31, 2012 compared to net cash flows provided by investing activities of $228.5 million for the year ended December 31, 2011, a decrease of $939.6 million. Investing activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July 1, 2011 merger with Frontier. Cash expenditures for properties, plants and equipment for 2012 decreased to $335.3 million from $374.2 million for the same period in 2011. These include HEP capital expenditures of $44.9 million and $216.2 million for the years ended December 31, 2012 and 2011, respectively, which include 2011 capital expenditures of $164.3 million to construct the UNEV Pipeline. Also for the years ended December 31, 2012 and 2011, we invested $2.0 million and $9.1 million, respectively, in Sabine Biofuels and $671.6 million and $561.9 million, respectively, in marketable securities and received proceeds of $297.7 million and $301.0 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. Our appropriated capital budget for 2014 is $185.0 million including both sustaining capital and major capital projects. We expect to spend approximately $400.0 million to $450.0 million in cash for capital projects appropriated in 2014 and prior years. In addition, we expect to spend $77.0 million on refinery turnarounds. Refinery turnaround spending is amortized over the useful life of the turnaround. Our new capital appropriation for 2014 and expected cash spending is as follows:



	New Appropriation		Expected Cash Spending Range
	(In millions)
Location:
El Dorado	$	43.0	$	85.0	–	$	96.0
Tulsa	22.0		54.0		–	61.0
Navajo	17.0		24.0		–	27.0
Cheyenne	74.0		80.0		–	90.0
Woods Cross	14.0		142.0		–	160.0
Corporate and Other	15.0		15.0		–	16.0
Total	$	185.0	$	400.0	–	$	450.0

Type:
Sustaining	$	51.0	$	66.0	–	$	74.0
Reliability and Growth	40.0		234.0		–	263.0
Compliance and Safety	94.0		100.0		–	113.0
Total	$	185.0	$	400.0	–	$	450.0

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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, MSAT2 which mandates a reduction in the benzene 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.

El Dorado Refinery

Capital projects at the El Dorado Refinery include naphtha fractionation, an additional hydrogen plant and a Low-Nox addition to the FCC unit flue gas scrubber. Continuing project work is planned to include upgrades to the FCC unit to improve liquid yield, upgrades to the crude unit desalter and a new tail gas treatment unit to reduce air emissions in compliance with the El Dorado Refinery's existing EPA consent decree.

Tulsa Refineries

Capital spending for the Tulsa Refineries in 2014 includes previously approved capital appropriations for a gasoline-blending system and numerous infrastructure upgrades. Spending on maintenance capital items and general improvements continues at an elevated level at the Tulsa Refineries due to perceived opportunities.

Navajo Refinery

The Navajo Refinery capital spending in 2014 will be principally on previously approved capital appropriations as well as maintenance capital spending. Included among previously approved capital projects is a $25.0 million upgrade to the Navajo Refinery's waste water treatment system.

Cheyenne Refinery

We are continuing with our previously approved plan to install a new hydrogen plant at the Cheyenne Refinery. The hydrogen plant, along with a previously approved naphtha fractionation project, is anticipated to allow us to reduce benzene content in Cheyenne gasoline production, while at the same time improving the refinery's overall liquid yields and light oils production. Previously appropriated projects still underway at Cheyenne include wastewater treatment plant improvements, a wet gas scrubber for the FCC unit to reduce air emissions, a redundant tail gas unit associated with sulfur recovery processes and additional investment in the waste water treatment plant to reduce selenium concentration in waste water.

Woods Cross Refinery

Engineering continues on our previously announced expansion project to increase planned processing capacity to 45,000 BPSD, which is expected to cost $300.0 million. On November 18, 2013, the Utah Division of Air Quality issued a revised air quality permit (the “Approval Order”) authorizing the expansion. On December 18, 2013, two local environmental groups filed an administrative appeal challenging the issuance of the Approval Order and seeking a stay of the Approval Order. The matter is now pending before an administrative law judge of the Utah Department of Environmental Quality. The expansion is expected to be completed in the fourth quarter of 2015. This project work includes a new rail loading rack for intermediates and finished products associated with refining waxy crude oil. Long lead equipment has been ordered and detailed engineering is approximately 60% completed. The expansion, and expected completion timeline and cost, are subject to the Woods Cross refinery successfully obtaining the Approval Order.

Regulatory compliance items or other presently existing or future environmental regulations / consent decrees could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements.

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 of several years, 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 2014 HEP capital budget is comprised of $7.3 million for maintenance capital expenditures and $26.2 million for expansion capital expenditures. HEP expects to spend approximately $52.0 million in cash for capital projects approved in 2014 plus those approved in prior years but not yet completed, such as the projects discussed below.

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HEP is proceeding with the expansion of its crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area. The expansion should provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to our New Mexico refining facilities. To complete the project, HEP plans to convert an existing refined products pipeline to crude oil service, construct several new pipeline segments, expand an existing pipeline and build new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to cost between $45.0 million and $50.0 million. The project is expected to provide increased capacity of up to 100,000 BPD across HEP's system and is expected to be in full service no later than August 2014.

UNEV is proceeding with a project to enhance its product terminal in Las Vegas, Nevada. HEP expects that the project will cost approximately $13.0 million with construction expected to be completed no later than the second quarter of 2014.

Cash Flows – Financing Activities

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Net cash flows used for financing activities were $1,160.0 million for the year ended December 31, 2013 compared to $772.8 million for the year ended December 31, 2012, an increase of $387.2 million. During the year ended December 31, 2013, we received $73.4 million from the sale of HEP common units, purchased $225.0 million in common stock, paid $645.9 million in dividends, paid $301.0 million upon the redemption of our 9.875% senior notes and recognized $2.6 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $310.6 million and repaid $368.6 million under the HEP Credit Agreement, paid distributions of $71.2 million to noncontrolling interests, purchased $5.3 million in HEP common units for recipients of its incentive grants and received proceeds of $73.4 million upon its March 2013 common unit offering. During the year ended December 31, 2012, we purchased $209.6 million in common stock, paid $658.1 million in dividends, received an $8.6 million payment pursuant to a structured share repurchase arrangement, paid $205.0 million in principal on our 9.875% senior notes and recognized $23.4 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $294.8 million in net proceeds upon the issuance of the HEP 6.5% senior notes, paid $185.0 million in principal on the HEP 6.25% senior notes, received $587.0 million and repaid $366.0 million under the HEP Credit Agreement, paid distributions of $58.8 million to noncontrolling interests, incurred $3.3 million in deferred financing costs and purchased $5.2 million in HEP common units in the open market for recipients of its incentive grants. Additionally, UNEV joint venture partner contributions of $6.0 million were received during the year ended December 31, 2012.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net cash flows used for financing activities were $772.8 million for the year ended December 31, 2012 compared to $217.1 million for the year ended December 31, 2011, an increase of $555.7 million. During the year ended December 31, 2012, we purchased $209.6 million in common stock, paid $658.1 million in dividends, received an $8.6 million payment pursuant to a structured share repurchase arrangement, paid $205.0 million in principal on our 9.875% senior notes and recognized $23.4 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $294.8 million in net proceeds upon the issuance of the HEP 6.5% senior notes, paid $185.0 million in principal on the HEP 6.25% senior notes, received $587.0 million and repaid $366.0 million under the HEP Credit Agreement, paid distributions of $58.8 million to noncontrolling interests, incurred $3.3 million in deferred financing costs and purchased $5.2 million in HEP common units in the open market for recipients of its incentive grants. During the year ended December 31, 2011, we purchased $42.8 million in common stock, paid $252.1 million in dividends, paid $8.2 million in principal on our senior notes and recognized $1.8 million excess tax benefits on our equity-based compensation. Additionally, we incurred $8.6 million in deferred financing costs. Also during this period, HEP received $75.8 million in net proceeds upon the issuance of HEP common units, received $118.0 million and repaid $77.0 million under the HEP Credit Agreement, paid distributions of $50.9 million to noncontrolling interests, incurred $3.2 million in deferred financing costs and purchased $1.6 million in HEP common units in the open market for recipients of its incentive grants. UNEV joint venture partner contributions received during the years ended December 31, 2012 and 2011 were $6.0 million and $33.5 million, respectively.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2013 in total and by period due beginning in 2014. 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.

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			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 ^{(1) (2)}
Long-term debt - principal ⁽³⁾	$	184,835	$	1,666	$	4,001	$	155,093	$	24,075
Long-term debt - interest ⁽⁴⁾	78,511		14,446		28,224		26,273		9,568
Supply agreements ⁽⁵⁾	902,799		599,759		279,030		13,720		10,290
Transportation and storage agreements ⁽⁶⁾	1,274,077		144,434		265,304		205,015		659,324
Other long-term obligations	25,734		9,838		14,890		1,006		—
Operating leases	63,194		16,835		28,600		13,297		4,462
	2,529,150		786,978		620,049		414,404		707,719

Holly Energy Partners
Long-term debt - principal ⁽⁷⁾	813,000		—		—		513,000		300,000
Long-term debt - interest ⁽⁸⁾	221,804		39,748		79,497		73,309		29,250
Pipeline operating and right of way leases	24,607		6,874		13,729		3,642		362
Other agreements	17,034		1,987		3,904		3,904		7,239
	1,076,445		48,609		97,130		593,855		336,851
Total	$	3,605,595	$	835,587	$	717,179	$	1,008,259	$	1,044,570

(1)

We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits of $9.0 million as of December 31, 2013 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 14 “Income Taxes” in the Notes to Consolidated Financial Statements.


(2)	Amounts shown do not include commitments to deliver barrels of crude oil held for other parties at our refineries. We periodically hold crude oil owned by third parties in the storage tanks at our refineries, which may be run through production. We will be obligated to deliver these stored barrels of crude oil upon the other party's request.


(3)	Our long-term debt consists of the $150.0 million principal balance on our 6.875% senior notes and a long-term financing obligation having a principal balance of $34.8 million at December 31, 2013.


(4)	Interest payments consist of interest on our 6.875% senior notes and on our long-term financing obligation.


(5)	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 2014 and 2020 using current market rates.


(6)	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 2014 and 2032.


(7)	HEP's long-term debt consists of the $150.0 million and the $300.0 million principal balances on the 8.25% and 6.5% HEP senior notes and $363.0 million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement expires in 2017.


(8)	Interest payments consist of interest on the 6.5% and 8.25% 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 applicable rate of 2.17% at December 31, 2013.

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.

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Variable Interest Entities

HEP is a VIE as defined under 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. 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 we consolidate HEP.

We have a 50% ownership interest in Sabine Biofuels, a biofuels production facility that is also a VIE. We do not hold a controlling financial interest, nor do we have the power to direct the activities that most significantly impact its financial performance. Accordingly, we account for our investment using the equity method of accounting.

Derivative Instruments

We have commodity price swap, interest rate swap, physical and NYMEX futures contracts that are measured at fair value and recognized as other assets or liabilities in our consolidated balance sheets. Changes in fair value to derivative instruments are recognized in earnings unless specific hedge accounting criteria is met. Derivatives meeting certain hedge accounting criteria are designated as “accounting hedges” and changes in fair value are recorded directly to other comprehensive income. These gains or losses are reclassified to earnings as the hedging instruments mature. Also, on a quarterly basis, hedge ineffectiveness on our accounting hedges is measured by comparing the change in fair value of the derivative contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is recognized in earnings. See Note 13 “Derivative Instruments and Hedging Activities” in the Notes to Consolidated Financial Statements.

Inventory Valuation

Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. 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 when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2013, many of our LIFO inventory layers were valued at historical costs that were established in years when price levels were generally lower; therefore, our results of operation are less sensitive to current market price reductions. As of December 31, 2013, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $273.0 million. 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.

Deferred Maintenance Costs

Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require routine “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. In order to minimize downtime during turnarounds, we often utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit.

Long-lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value, which is generally determined under an income approach using forecasted cash flows associated with the underlying asset. Estimates of future cash flows require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2013, 2012 and 2011.

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Intangibles and Goodwill

Intangible assets are assets (other than financial assets) that lack physical substance. 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 intangible assets with indefinite useful lives are not amortized while intangible assets with finite useful lives are amortized on 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 possibility of impairment. Our analysis entails a comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. There were no impairments of intangible assets or goodwill during the years ended December 31, 2013, 2012 and 2011.

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. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. 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.

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;


•	costs of crude oil and related grade differentials;


•	prices of refined products; and


•	our refining margins.

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As of December 31, 2013, 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	2014	2015	2016	2017	Unit of Measure

Natural gas price swap - long	76,800,000	19,200,000	19,200,000	19,200,000	19,200,000	MMBTU
Natural gas price swap - short	38,400,000	9,600,000	9,600,000	9,600,000	9,600,000	MMBTU
WTI price swap - long	18,797,500	16,242,500	2,555,000	—	—	Barrels
Ultra-low sulfur diesel price swap - short	15,512,500	12,957,500	2,555,000	—	—	Barrels
Sub octane gasoline price swap - short	3,285,000	3,285,000	—	—	—	Barrels
WCS price swap - long	6,387,500	6,387,500	—	—	—	Barrels
NYMEX futures (WTI) - short	1,946,000	1,946,000	—	—	—	Barrels
Physical contracts - long	300,000	300,000	—	—	—	Barrels
Physical contracts - short	300,000	300,000	—	—	—	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	2013		2012
	(In thousands)
Hypothetical 10% change in underlying commodity prices	$	69,228	$	29,230

Interest Rate Risk Management

HEP uses interest rate swaps to manage its exposure to interest rate risk.

As of December 31, 2013, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.99%. This swap matures in February 2016. HEP has two additional interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.74%. Both of these swap contracts mature in July 2017. These swap contracts have been designated as cash flow hedges.

The market risk inherent in our fixed-rate debt and positions 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 our 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 these debt instruments as of December 31, 2013 is presented below:



	Outstanding Principal		Estimated Fair Value		Estimated Change in Fair Value
	(In thousands)
HollyFrontier Senior Notes	$	150,000	$	161,250	$	3,443
HEP Senior Notes	$	450,000	$	471,750	$	12,884

For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2013, outstanding borrowings under the HEP Credit Agreement were $363.0 million. By means of its cash flow hedges, HEP has effectively converted the variable rate on $305.0 million of outstanding principal to a weighted average fixed rate of 2.87%.

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At December 31, 2013, our marketable securities included investments in investment grade, highly-liquid investments with maturities generally not greater than one year from the date of purchase and hence the interest rate market risk implicit in these investments is low. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

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.


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 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.

Set forth below is our calculation of EBITDA.



	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Net income attributable to HollyFrontier stockholders	$	735,842		$	1,727,172		$	1,023,397
Add income tax provision	391,576			1,027,962			581,991
Add interest expense ⁽¹⁾	90,159			104,186			78,323
Subtract interest income	(5,556		)	(4,786		)	(1,284		)
Add depreciation and amortization	303,446			242,868			159,707
EBITDA	$	1,515,467		$	3,097,402		$	1,842,134

(1) Includes loss on early extinguishment of debt of $22.1 million for the year ended December 31, 2013.

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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 barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. These two margins do not include the effect of 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.

Refinery Gross and Net Operating Margins

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

Reconciliation of produced refined product sales to total sales and other revenues



	Years Ended December 31,
	2013			2012			2011
	(Dollars in thousands, except per barrel amounts)
Consolidated
Average sales price per produced barrel sold	$	115.60		$	119.48		$	118.82
Times sales of produced refined products sold (BPD)	410,730			431,060			332,720
Times number of days in period	365			366			365
Produced refined product sales	$	17,330,342		$	18,850,116		$	14,429,833

Total produced refined product sales	$	17,330,342		$	18,850,116		$	14,429,833
Add refined product sales from purchased products and rounding ⁽¹⁾	1,581,395			572,206			350,843
Total refined product sales	18,911,737			19,422,322			14,780,676
Add direct sales of excess crude oil ⁽²⁾	1,052,915			505,971			558,855
Add other refining segment revenue ⁽³⁾	140,791			114,662			52,899
Total refining segment revenue	20,105,443			20,042,955			15,392,430
Add HEP segment sales and other revenues	307,053			288,501			212,995
Add corporate and other revenues	1,314			1,048			1,098
Subtract consolidations and eliminations	(253,250		)	(241,780		)	(166,995		)
Sales and other revenues	$	20,160,560		$	20,090,724		$	15,439,528

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Reconciliation of average cost of products per produced barrel sold to total cost of products sold



	Years Ended December 31,
	2013			2012			2011
	(Dollars in thousands, except per barrel amounts)
Consolidated
Average cost of products per produced barrel sold	$	99.61		$	94.59		$	98.18
Times sales of produced refined products sold (BPD)	410,730			431,060			332,720
Times number of days in period	365			366			365
Cost of products for produced products sold	$	14,933,178		$	14,923,271		$	11,923,254

Total cost of products for produced products sold	$	14,933,178		$	14,923,271		$	11,923,254
Add refined product costs from purchased products and rounding ⁽¹⁾	1,553,476			572,755			351,788
Total cost of refined products sold	16,486,654			15,496,026			12,275,042
Add crude oil cost of direct sales of excess crude oil ⁽²⁾	1,048,224			492,790			550,619
Add other refining segment cost of products sold ⁽⁴⁾	106,241			90,132			18,672
Total refining segment cost of products sold	17,641,119			16,078,948			12,844,333
Subtract consolidations and eliminations	(248,892		)	(238,305		)	(164,255		)
Costs of products sold (exclusive of depreciation and amortization)	$	17,392,227		$	15,840,643		$	12,680,078

Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses



	Years Ended December 31,
	2013			2012			2011
	(Dollars in thousands, except per barrel amounts)
Consolidated
Average refinery operating expenses per produced barrel sold	$	6.15		$	5.49		$	5.36
Times sales of produced refined products sold (BPD)	410,730			431,060			332,720
Times number of days in period	365			366			365
Refinery operating expenses for produced products sold	$	921,986		$	866,146		$	650,933

Total refinery operating expenses for produced products sold	$	921,986		$	866,146		$	650,933
Add refining segment pension settlement costs	31,657			—			—
Add other refining segment operating expenses and rounding ⁽⁵⁾	39,812			37,231			35,659
Total refining segment operating expenses	993,455			903,377			686,592
Add HEP segment operating expenses	97,081			89,395			63,029
Add corporate and other costs	1,739			2,721			427
Subtract consolidations and eliminations	(1,425		)	(527		)	(1,967		)
Operating expenses (exclusive of depreciation and amortization)	$	1,090,850		$	994,966		$	748,081

Table of Content

Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues



	Years Ended December 31,
	2013			2012			2011
	(Dollars in thousands, except per barrel amounts)
Consolidated
Net operating margin per barrel	$	9.84		$	19.40		$	15.28
Add average refinery operating expenses per produced barrel	6.15			5.49			5.36
Refinery gross margin per barrel	15.99			24.89			20.64
Add average cost of products per produced barrel sold	99.61			94.59			98.18
Average sales price per produced barrel sold	$	115.60		$	119.48		$	118.82
Times sales of produced refined products sold (BPD)	410,730			431,060			332,720
Times number of days in period	365			366			365
Produced refined product sales	$	17,330,342		$	18,850,116		$	14,429,833

Total produced refined product sales	$	17,330,342		$	18,850,116		$	14,429,833
Add refined product sales from purchased products and rounding ⁽¹⁾	1,581,395			572,206			350,843
Total refined product sales	18,911,737			19,422,322			14,780,676
Add direct sales of excess crude oil ⁽²⁾	1,052,915			505,971			558,855
Add other refining segment revenue ⁽³⁾	140,791			114,662			52,899
Total refining segment revenue	20,105,443			20,042,955			15,392,430
Add HEP segment sales and other revenues	307,053			288,501			212,995
Add corporate and other revenues	1,314			1,048			1,098
Subtract consolidations and eliminations	(253,250		)	(241,780		)	(166,995		)
Sales and other revenues	$	20,160,560		$	20,090,724		$	15,439,528


(1)	We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.

(2)

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 inventory and then upon sale as cost of products sold. Additionally, at times 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 carryover cost.


(3)	Other refining segment revenue includes the incremental revenues associated with NK Asphalt and miscellaneous revenue.


(4)	Other refining segment cost of products sold includes the incremental cost of products for NK Asphalt and miscellaneous costs.


(5)	Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of NK Asphalt.

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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.

Management assessed the Company's internal control over financial reporting as of December 31, 2013 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 (1992 framework). Based on this assessment, management concludes that, as of December 31, 2013, 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, 2013. That report appears on page 55.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

and Stockholders of HollyFrontier Corporation

We have audited HollyFrontier Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework), (the “COSO criteria”). HollyFrontier Corporation'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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

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

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

In our opinion, HollyFrontier Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of HollyFrontier Corporation as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013 and our report dated February 25, 2014 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 25, 2014

Index to Consolidated Financial Statements



	Page Reference

Report of Independent Registered Public Accounting Firm	57

Consolidated Balance Sheets at December 31, 2013 and 2012	58

Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011	58

Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	59

Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	60

Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011	61

Notes to Consolidated Financial Statements	62

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

and Stockholders of HollyFrontier Corporation

We have audited the accompanying consolidated balance sheets of HollyFrontier Corporation (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of HollyFrontier Corporation at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), HollyFrontier Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework), and our report dated February 25, 2014 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 25, 2014

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents (HEP: $6,352 and $5,237, respectively)	$	940,103		$	1,757,699
Marketable securities	725,160			630,586
Total cash, cash equivalents and short-term marketable securities	1,665,263			2,388,285
Accounts receivable: Product and transportation (HEP: $34,736 and $38,097, respectively)	665,098			587,728
Crude oil resales	43,704			46,502
	708,802			634,230
Inventories: Crude oil and refined products	1,241,448			1,238,678
Materials, supplies and other (HEP: $1,591 and $1,259, respectively)	112,799			80,954
	1,354,247			1,319,632
Income taxes receivable	109,376			74,957
Prepayments and other (HEP: $2,283 and $2,360, respectively)	58,756			53,161
Total current assets	3,896,444			4,470,265

Properties, plants and equipment, at cost (HEP: $1,199,594 and $1,155,710, respectively)	4,343,857			3,943,114
Less accumulated depreciation (HEP: $(194,619) and $(141,154), respectively)	(949,261		)	(748,414		)
	3,394,596			3,194,700
Marketable securities (long-term)	—			5,116
Other assets: Turnaround costs	258,436			151,764
Goodwill (HEP: $288,991 and $288,991, respectively)	2,331,922			2,338,302
Intangibles and other (HEP: $74,979 and $76,300, respectively)	175,341			168,850
	2,765,699			2,658,916
Total assets	$	10,056,739		$	10,328,997

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $22,898 and $12,030, respectively)	$	1,325,376		$	1,314,151
Accrued liabilities (HEP: $28,668 and $23,705, respectively)	125,115			195,077
Deferred income tax liabilities	223,999			145,216
Total current liabilities	1,674,490			1,654,444

Long-term debt (HEP: $807,630 and $864,673, respectively)	997,519			1,336,238
Deferred income taxes (HEP: $5,287 and $4,951, respectively)	616,842			536,670
Other long-term liabilities (HEP: $35,918 and $28,683, respectively)	158,490			158,987

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; 255,962,866 shares issued as of December 31, 2013 and December 31, 2012	2,560			2,560
Additional capital	3,990,630			3,911,353
Retained earnings	3,144,480			3,054,769
Accumulated other comprehensive income (loss)	822			(8,425		)
Common stock held in treasury, at cost – 57,132,515 and 52,411,370 shares as of December 31, 2013 and December 31, 2012, respectively	(1,138,872		)	(907,303		)
Total HollyFrontier stockholders’ equity	5,999,620			6,052,954
Noncontrolling interest	609,778			589,704
Total equity	6,609,398			6,642,658
Total liabilities and equity	$	10,056,739		$	10,328,997

Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2013 and December 31, 2012. HEP is a consolidated variable interest entity.

See accompanying notes.

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)



	Years Ended December 31,
	2013			2012			2011

Sales and other revenues	$	20,160,560		$	20,090,724		$	15,439,528
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	17,392,227			15,840,643			12,680,078
Operating expenses (exclusive of depreciation and amortization)	1,090,850			994,966			748,081
General and administrative expenses (exclusive of depreciation and amortization)	127,963			128,101			120,114
Depreciation and amortization	303,446			242,868			159,707
Total operating costs and expenses	18,914,486			17,206,578			13,707,980
Income from operations	1,246,074			2,884,146			1,731,548
Other income (expense):
Earnings (loss) of equity method investments	(2,072		)	2,923			2,300
Interest income	5,556			4,786			1,284
Interest expense	(68,050		)	(104,186		)	(78,323		)
Loss on early extinguishment of debt	(22,109		)	—			—
Gain on sale of marketable equity securities	—			326			—
Merger transaction costs	—			—			(15,114		)
	(86,675		)	(96,151		)	(89,853		)
Income before income taxes	1,159,399			2,787,995			1,641,695
Income tax provision:
Current	277,172			932,554			590,851
Deferred	114,404			95,408			(8,860		)
	391,576			1,027,962			581,991
Net income	767,823			1,760,033			1,059,704
Less net income attributable to noncontrolling interest	31,981			32,861			36,307
Net income attributable to HollyFrontier stockholders	$	735,842		$	1,727,172		$	1,023,397
Earnings per share attributable to HollyFrontier stockholders:
Basic	$	3.66		$	8.41		$	6.46
Diluted	$	3.64		$	8.38		$	6.42
Average number of common shares outstanding:
Basic	200,419			204,379			157,948
Diluted	201,234			205,274			158,756

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)



	Years Ended December 31,
	2013			2012			2011

Net income	$	767,823		$	1,760,033		$	1,059,704
Other comprehensive income (loss):
Securities available-for-sale:
Unrealized gain (loss) on marketable securities	73			149			(530		)
Reclassification adjustments to net income on sale or maturity of marketable securities	(39		)	(385		)	14
Net unrealized gain (loss) on marketable securities	34			(236		)	(516		)
Hedging instruments:
Change in fair value of cash flow hedging instruments	(7,614		)	(252,817		)	171,252
Reclassification adjustments to net income on settlement of cash flow hedging instruments	(14,318		)	56,683			5,643
Amortization of unrealized loss attributable to discontinued cash flow hedges	1,749			5,095			41
Net unrealized gain (loss) on hedging instruments	(20,183		)	(191,039		)	176,936
Pension and other post-retirement benefit obligations:
Loss on pension plan	—			(3,485		)	(2,191		)
Pension plan loss reclassified to net income	37,589			1,956			2,302
Gain (loss) on post-retirement healthcare plan	3,301			55,402			(3,673		)
Post-retirement healthcare plan (gain) loss reclassified to net income	(4,040		)	(1,952		)	158
Gain (loss) on retirement restoration plan	632			(593		)	(281		)
Retirement restoration plan loss reclassified to net income	111			63			99
Net change in pension and other post-retirement benefit obligations	37,593			51,391			(3,586		)
Other comprehensive income (loss) before income taxes	17,444			(139,884		)	172,834
Income tax expense (benefit)	5,882			(54,950		)	66,138
Other comprehensive income (loss)	11,562			(84,934		)	106,696
Total comprehensive income	779,385			1,675,099			1,166,400
Less noncontrolling interest in comprehensive income	34,296			34,225			39,122
Comprehensive income attributable to HollyFrontier stockholders	$	745,089		$	1,640,874		$	1,127,278

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	767,823		$	1,760,033		$	1,059,704
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	303,446			242,868			159,707
Earnings of equity method investments, net of distributions	5,198			701			387
Loss on early extinguishment of debt attributable to unamortized discount	7,948			—			—
Gain on sale of marketable equity securities	—			(326		)	—
Deferred income taxes	114,404			95,408			(8,860		)
Equity-based compensation expense	35,775			39,203			26,825
Change in fair value – derivative instruments	(53,185		)	52,335			306
Loss on settlement of retirement benefit obligations, net of contributions	16,771			(19,524		)	(6,049		)
(Increase) decrease in current assets:
Accounts receivable	(68,832		)	71,627			373,591
Inventories	(15,929		)	(205,013		)	(56,828		)
Income taxes receivable	(34,419		)	19,056			(36,394		)
Prepayments and other	1,377			(9,366		)	(14,214		)
Increase (decrease) in current liabilities:
Accounts payable	2,068			(194,051		)	(251,428		)
Income taxes payable	—			(40,366		)	72,091
Accrued liabilities	(41,229		)	(39,851		)	60,467
Turnaround expenditures	(193,920		)	(159,707		)	(32,023		)
Other, net	21,878			49,660			(8,891		)
Net cash provided by operating activities	869,174			1,662,687			1,338,391

Cash flows from investing activities:
Additions to properties, plants and equipment	(373,271		)	(290,334		)	(158,026		)
Additions to properties, plants and equipment – HEP	(51,856		)	(44,929		)	(216,215		)
Acquisition of trucking operations	(11,301		)	—			—
Proceeds from sale of property and equipment	7,802			—			—
Increase in cash due to merger with Frontier	—			—			872,739
Investment in Sabine Biofuels	(3,000		)	(2,000		)	(9,125		)
Net advances to Sabine Biofuels	(5,740		)	—			—
Purchases of marketable securities	(935,512		)	(671,552		)	(561,899		)
Sales and maturities of marketable securities	846,143			297,711			301,020
Net cash provided by (used for) investing activities	(526,735		)	(711,104		)	228,494

Cash flows from financing activities:
Borrowings under credit agreement – HEP	310,600			587,000			118,000
Repayments under credit agreement – HEP	(368,600		)	(366,000		)	(77,000		)
Net proceeds from issuance of senior notes – HEP	—			294,750			—
Redemption of senior notes	(300,973		)	(205,000		)	(8,203		)
Principal tender on senior notes - HEP	—			(185,000		)	—
Proceeds from sale of HEP common units	73,444			—			—
Proceeds from common unit offerings – HEP	73,444			—			75,815
Purchase of treasury stock	(225,023		)	(209,600		)	(42,795		)
Structured stock repurchase arrangement	—			8,620			—
Contribution from joint venture partner	—			6,000			33,500
Dividends	(645,920		)	(658,085		)	(252,133		)
Distributions to noncontrolling interest	(71,201		)	(58,788		)	(50,874		)
Excess tax benefit from equity-based compensation	2,562			23,361			1,804
Purchase of units for incentive grants – HEP	(5,313		)	(5,240		)	(1,641		)
Deferred financing costs and other	(3,055		)	(4,806		)	(13,555		)
Net cash used for financing activities	(1,160,035		)	(772,788		)	(217,082		)

Cash and cash equivalents:
Increase (decrease) for the period	(817,596		)	178,795			1,349,803
Beginning of period	1,757,699			1,578,904			229,101
End of period	$	940,103		$	1,757,699		$	1,578,904

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	76,647		$	101,709		$	78,483
Income taxes	$	372,846		$	983,618		$	552,487

See accompanying notes.

Table of Content

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, 2010	$	1,526		$	193,615		$	1,206,328		$	(26,246	)	$	(677,804	)	$	590,720		$	1,288,139
Net income	—			—			1,023,397			—			—			36,307			1,059,704
Dividends	—			—			(265,069		)	—			—			—			(265,069		)
Distribution to noncontrolling interest holders	—			—			—			—			—			(50,874		)	(50,874		)
Other comprehensive income, net of tax	—			—			—			103,881			—			2,815			106,696
Issuance of common stock upon merger with Frontier Oil Corporation	1,037			3,704,203			—			—			—			—			3,705,240
Allocated equity on HEP common unit issuances, net of tax	—			(44,885		)	—			238			—			16,852			(27,795		)
Contribution from joint venture partner	—			—			—			—			—			36,500			36,500
Issuance of common stock under incentive compensation plans, net of forfeitures	—			(20,150		)	—			—			20,150			—			—
Equity-based compensation, net of tax benefit	—			26,584			—			—			—			2,046			28,630
Purchase of treasury stock	—			—			—			—			(42,795		)	—			(42,795		)
Other	—			—			—			—			—			(2,476		)	(2,476		)
Balance at December 31, 2011	$	2,563		$	3,859,367		$	1,964,656		$	77,873		$	(700,449	)	$	631,890		$	5,835,900
Net income	—			—			1,727,172			—			—			32,861			1,760,033
Dividends	—			—			(637,059		)	—			—			—			(637,059		)
Distributions to noncontrolling interest holders	—			—			—			—			—			(58,788		)	(58,788		)
Other comprehensive income, net of tax	—			—			—			(86,298		)	—			1,364			(84,934		)
Allocated equity on HEP common unit issuances, net of tax	—			11,469			—			—			—			(18,768		)	(7,299		)
Contribution from joint venture partner	—			—			—			—			—			3,000			3,000
Issuance of common stock under incentive compensation plans, net of forfeitures	(3		)	(27,809		)	—			—			27,812			—			—
Equity-based compensation, net of tax benefit	—			59,706			—			—			—			2,858			62,564
Purchase of treasury stock	—			—			—			—			(234,666		)	—			(234,666		)
Net proceeds received under structured share repurchase arrangement	—			8,620			—			—			—			—			8,620
Purchase of HEP units for restricted grants	—			—			—			—			—			(4,713		)	(4,713		)
Balance at December 31, 2012	$	2,560		$	3,911,353		$	3,054,769		$	(8,425	)	$	(907,303	)	$	589,704		$	6,642,658
Net income	—			—			735,842			—			—			31,981			767,823
Dividends	—			—			(646,131		)	—			—			—			(646,131		)
Distributions to noncontrolling interest holders	—			—			—			—			—			(71,201		)	(71,201		)
Other comprehensive income, net of tax	—			—			—			9,247			—			2,315			11,562
Allocated equity on HEP common unit issuances, net of tax	—			54,184			—			—			—			58,702			112,886
Issuance of common stock under incentive compensation plans, net of forfeitures	—			(9,669		)	—			—			9,669			—			—
Equity-based compensation, net of tax benefit	—			34,762			—			—			—			3,575			38,337
Purchase of treasury stock	—			—			—			—			(241,238		)	—			(241,238		)
Purchase of HEP units for restricted grants	—			—			—			—			—			(5,313		)	(5,313		)
Other	—			—			—			—			—			15			15
Balance at December 31, 2013	$	2,560		$	3,990,630		$	3,144,480		$	822		$	(1,138,872	)	$	609,778		$	6,609,398

See accompanying notes.

Table of Content

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 merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC” (see Note 2). Accordingly, these financial statements include Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

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. As of December 31, 2013, 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 NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New Mexico;


•	owned a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur, Texas; and

•

owned a 39% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”) and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

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 we consolidate HEP.

We have a 50% ownership interest in Sabine Biofuels, a biofuels production facility that is a VIE. We do not hold a controlling financial interest, nor do we have the power to direct the activities that most significantly impact its financial performance. Accordingly, we account for our investment using the equity method of accounting.

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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 certificates of deposit, 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 $2.4 million and $2.5 million at December 31, 2013 and 2012, 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 are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil unfinished and finished refined products and the average cost method for materials and supplies, 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 estimated selling prices. 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.

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.

Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value, which is generally determined under an income approach using the forecasted cash flows associated with the underlying asset. Estimates of future cash flows require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2013, 2012 and 2011.

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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.

Our asset retirement obligations were $19.1 million and $18.1 million at December 31, 2013 and 2012, respectively, which are included in “Other long-term liabilities” in our consolidated balance sheets. Accretion expense was insignificant for the years ended December 31, 2013, 2012 and 2011.

Intangibles and Goodwill: Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized while, intangible assets with finite useful lives are amortized on 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 analysis entails a comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates minimum annual cash inflows of $24.7 million and has an expected remaining term through 2035. The transportation agreement is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $2.0 million. The balance of this transportation agreement was $42.5 million and $44.5 million at December 31, 2013 and 2012, respectively, and is presented net of accumulated amortization of $17.7 million and $15.7 million, respectively, in “Intangibles and other” in our consolidated balance sheets. There were no impairments of intangible assets or goodwill during the years ended December 31, 2013, 2012 and 2011.

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% and use the equity method of accounting for investments in which we have a 50% or less ownership interest. 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 25% joint venture interest in the SLC Pipeline that is accounted for using the equity method of accounting. As of December 31, 2013, HEP's underlying equity in the SLC Pipeline was $59.6 million compared to its recorded investment balance of $24.7 million, a difference of $34.9 million. This is attributable to the difference between HEP's contributed capital and its allocated equity at formation of the SLC Pipeline. This difference is being amortized as an adjustment to HEP's pro-rata share of earnings.

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.

Depreciation: Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 20 to 25 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.

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 carryover cost. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs.

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Continued

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.

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.

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 current and accumulated 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.


NOTE 2:	Holly-Frontier Merger

In accordance with the merger agreement, we issued approximately 102.8 million shares of HollyFrontier common stock in exchange for outstanding shares of Frontier common stock to former Frontier stockholders. Each outstanding share of Frontier common stock was converted into 0.4811 shares of HollyFrontier common stock with any fractional shares paid in cash. The aggregate consideration paid in connection with the merger was approximately $3.7 billion. This is based on our July 1, 2011 market closing price of $35.93 and includes a portion of the fair value of the outstanding equity-based awards assumed from Frontier that relates to pre-merger services.

Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011, which consists of crude oil refining and the wholesale marketing of refined petroleum products produced at the El Dorado and Cheyenne Refineries, which serve markets in the Rocky Mountain and Plains States regions of the United States.

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Continued


NOTE 3:	Variable Interest Entities

Holly Energy Partners

HEP, a consolidated VIE, is a publicly held master limited partnership that was formed to acquire, own and operate the petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. HEP also owns and operates refined product pipelines and terminals, located primarily in Texas, that serve Alon's refinery in Big Spring, Texas.

As of December 31, 2013, we owned a 39% interest in HEP, including the 2% general partner interest. As the general partner of HEP, we have the sole ability to direct the activities that most significantly impact HEP's financial performance. We are the primary beneficiary of HEP's earnings and cash flows and therefore we consolidate HEP. See Note 21 for supplemental guarantor/non-guarantor financial information, including HEP balances included in these consolidated financial statements.

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, 2013. 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. With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse to our other assets. Any recourse to HEP’s 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. 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.

HEP's recent acquisitions (2011 through present) are summarized below:

UNEV Interest Transaction

On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in cash and 1.0 million HEP common units.

Legacy Frontier Tankage and Terminal Asset Transaction

Transportation Agreements

HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2013, these agreements result in minimum annualized payments to HEP of $225.5 million.

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

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Continued

HEP's recent common unit issuances (2011 through present) are summarized below:

2013 Issuances

2012 Issuances

In July 2012, HEP issued 1.0 million of its common units to us as partial consideration for its purchase of our 75% interest in UNEV.

2011 Issuances

In December 2011, HEP issued 1.5 million of its common units priced at $53.50 per unit. Aggregate net proceeds of $75.8 million were used to repay a portion of the $150 million in promissory notes issued to us in connection with HEP's November 2011 asset acquisition from us. This repayment to us is eliminated in our consolidated financial statements.

In November 2011, HEP issued 3.8 million of its common units to us as partial consideration for its purchase from us of certain tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries.

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

Sabine Biofuels

We have a 50% ownership interest in Sabine Biofuels, an unconsolidated VIE. This investment, accounted for using the equity method of accounting, had a carrying amount of $8.5 million at December 31, 2013 and is classified as a noncurrent asset under “Intangibles and other” in our consolidated balance sheets. Also, we have extended a working capital facility to Sabine Biofuels having an outstanding balance of $9.9 million at December 31, 2013.


NOTE 4:	Financial Instruments

Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts payable, debt and derivative instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value. HEP's outstanding credit agreement borrowings also approximate fair value as interest rates are reset frequently at current interest rates.

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.

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The carrying amounts and estimated fair values of our investments in marketable securities, derivative instruments and senior notes at December 31, 2013 and December 31, 2012 were as follows:



					Fair Value by Input Level
Financial Instrument	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
			(In thousands)
December 31, 2013
Assets:
Marketable securities	$	725,160	$	725,160	$	—	$	725,160	$	—
Commodity price swaps	43,284		43,284		—		36,312		6,972
HEP interest rate swaps	1,670		1,670		—		1,670		—
Total assets	$	770,114	$	770,114	$	—	$	763,142	$	6,972

Liabilities:
NYMEX futures contracts	$	3,569	$	3,569	$	3,569	$	—	$	—
Commodity price swaps	83,349		83,349		—		41,059		42,290
HollyFrontier senior notes	155,054		161,250		—		161,250		—
HEP senior notes	444,630		471,750		—		471,750		—
HEP interest rate swaps	1,814		1,814		—		1,814		—
Total liabilities	$	688,416	$	721,732	$	3,569	$	675,873	$	42,290



December 31, 2012
Assets:
Marketable securities	$	635,702	$	635,702	$	—	$	635,702	$	—
Commodity price swaps	17,383		17,383		—		6,151		11,232
Total assets	$	653,085	$	653,085	$	—	$	641,853	$	11,232

Liabilities:
NYMEX futures contracts	$	5,563	$	5,563	$	5,563	$	—	$	—
Commodity price swaps	83,982		83,982		—		39,092		44,890
HollyFrontier senior notes	435,254		470,990		—		470,990		—
HEP senior notes	443,673		484,125		—		484,125		—
HEP interest rate swaps	3,430		3,430		—		3,430		—
Total liabilities	$	971,902	$	1,048,090	$	5,563	$	997,637	$	44,890

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 and derivative instruments consisting of commodity price swaps 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. The fair value of the marketable securities and senior notes is based on values provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input.

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Level 3 Financial Instruments

We have commodity price swap contracts that relate to forecasted sales of diesel and unleaded gasoline and forecasted purchases of WCS for which quoted forward market prices are not readily available. The forward rate used to value these price swaps is 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, 2013 and 2012:



		Years Ended December 31,
Level 3 Financial Instruments		2013			2012
	(In thousands)
Asset (liability) balance at beginning of period		$	(33,658	)	$	31,616
Change in fair value:
Recognized in other comprehensive income		(71,751		)	(120,966		)
Recognized in cost of products sold		35,236			(39,463		)
Settlement date fair value of contractual maturities:
Recognized in sales and other revenues		20,060			98,750
Recognized in cost of products sold		14,795			(3,595		)
Liability balance at end of period		$	(35,318	)	$	(33,658	)

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in an estimated fair value change of $3.5 million.


NOTE 5:	Earnings Per Share

Basic earnings per share is calculated as net income 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 variable restricted and variable performance shares. The following is a reconciliation of the denominators of the basic and diluted per share computations for net income attributable to HollyFrontier stockholders:



	Years Ended December 31,
	2013		2012		2011
	(In thousands, except per share data)
Earnings attributable to HollyFrontier stockholders	$	735,842	$	1,727,172	$	1,023,397
Participating securities' share in earnings	2,754		7,648		3,474
Net income attributable to common shares	733,088		1,719,524		1,019,923
Average number of shares of common stock outstanding	200,419		204,379		157,948
Effect of dilutive variable restricted shares andperformance share units⁽¹⁾	815		895		808
Average number of shares of common stock outstanding assuming dilution	201,234		205,274		158,756
Basic earnings per share	$	3.66	$	8.41	$	6.46
Diluted earnings per share	$	3.64	$	8.38	$	6.42

(1) Excludes anti-dilutive restricted and performance share units of:	166		166		—

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NOTE 6:	Stock-Based Compensation

As of December 31, 2013, 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 $32.2 million, $36.3 million and $24.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) 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 $3.6 million, $2.7 million and $2.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Restricted Stock and Restricted Stock Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees restricted stock and restricted stock unit awards with awards generally vesting over a period of one to three years. Restricted stock award recipients are generally entitled to all the rights of absolute ownership of the restricted shares from the date of grant (unless a recipient's tax election requires otherwise) including the right to vote the shares and to receive dividends. Upon vesting, restrictions on the restricted shares 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 market price as of the date of grant 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, 2013 is presented below:



Restricted Stock and Restricted Stock Units	Grants		Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($000)

Outstanding at January 1, 2013 (non-vested)	843,527		$	34.52
Granted	401,394		42.00
Vesting (transfer / conversion to common stock)	(491,565	)	33.04
Forfeited	(15,794	)	35.86
Outstanding at December 31, 2013 (non-vested)	737,562		$	39.54	$	36,650

For the year ended December 31, 2013, 491,565 restricted stock and restricted stock units vested having a grant date fair value of $16.2 million. For the years ended December 31, 2012 and 2011, we granted restricted stock having a weighted average grant date fair value of $37.27 and $28.61 per unit, respectively. Additionally, restricted stock vested during these periods having grant date fair values of $27.7 million and $9.1 million, respectively. As of December 31, 2013, there was $19.6 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 1.3 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 either a “financial performance” or “market performance” criteria, or both.

The fair value of performance share unit awards subject to financial performance criteria is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of December 31, 2013, estimated share payouts for outstanding non-vested performance share unit awards ranged approximately from 110% to 165%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

For the performance share units subject to market performance criteria, performance is calculated as the total shareholder return achieved by HollyFrontier stockholders compared with the average shareholder return achieved by an equally-weighted peer group of independent refining companies over a three-year period. These share unit awards are valued using a Monte Carlo valuation model, which simulates future stock price movements using key inputs including grant date stock prices, expected stock price performance, expected rate of return and volatility. These units are payable in stock based on share price performance relative to the defined peer group and can range from zero to 200% of the initial target award.

A summary of performance share unit activity and changes during the year ended December 31, 2013 is presented below:



Performance Share Units	Grants

Outstanding at January 1, 2013 (non-vested)	875,574
Granted	256,671
Vesting and transfer of ownership to recipients	(126,460	)
Forfeited	(22,175	)
Outstanding at December 31, 2013 (non-vested)	983,610

For the year ended December 31, 2013, we issued 210,819 shares of our common stock, representing a 167% payout on vested performance share units having a grant date fair value of $11.6 million. For the years ended December 31, 2012 and 2011, we issued common stock upon the vesting of the performance share units having a grant date fair value of $6.0 million and $2.6 million, respectively. As of December 31, 2013, based on the weighted-average grant date fair value of $38.75 per share, there was $28.0 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.6 years.


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

Our investment portfolio at December 31, 2013 consisted of cash, cash equivalents and investments in marketable securities.

We currently 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. As a result, they are reported at fair value using quoted market prices. 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:



	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value (Net Carrying Amount)
	(In thousands)
December 31, 2013
Certificates of deposit	$	74,802	$	21	$	(1	)	$	74,822
Commercial paper	78,216		28		—			78,244
Corporate debt securities	96,889		6		(44		)	96,851
State and political subdivisions debt securities	475,235		49		(41		)	475,243
Total marketable securities	$	725,142	$	104	$	(86	)	$	725,160

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Continued



	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value (Net Carrying Amount)
	(In thousands)
December 31, 2012
Certificates of deposit	$	82,791	$	14	$	(6	)	$	82,799
Commercial paper	45,737		17		—			45,754
Corporate debt securities	49,587		2		(30		)	49,559
State and political subdivisions debt securities	457,615		26		(51		)	457,590
Total marketable securities	$	635,730	$	59	$	(87	)	$	635,702

Interest income recognized on our marketable securities was $2.1 million and $1.1 million for the years ended December 31, 2013 and 2012, respectively.


NOTE 8:	Inventories

Inventory consists of the following components:



	December 31,
	2013		2012
	(In thousands)
Crude oil	$	567,281	$	502,978
Other raw materials and unfinished products⁽¹⁾	154,534		150,090
Finished products⁽²⁾	519,633		585,610
Process chemicals⁽³⁾	3,504		3,514
Repairs and maintenance supplies and other	109,295		77,440
Total inventory	$	1,354,247	$	1,319,632


(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.

The excess of current cost over the LIFO value of inventory was $273.0 million and $134.0 million at December 31, 2013 and 2012, respectively. For the year ended December 31, 2013, we recognized a charge of $9.2 million to cost of products sold as we liquidated certain quantities of LIFO inventory that were carried at historical acquisition costs above market prices at the time of liquidation. For the years ended December 31, 2012 and 2011, we recognized reductions of $4.2 million and $0.1 million, respectively, to cost of products sold due to the liquidation of certain quantities of LIFO inventory that were carried at historical acquisition costs below market value at the time of liquidation.

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Continued


NOTE 9:	Properties, Plants and Equipment



	December 31,
	2013			2012
	(In thousands)
Land, buildings and improvements	$	235,625		$	198,610
Refining facilities	2,510,750			2,261,733
Pipelines and terminals	1,158,288			1,113,080
Transportation vehicles	41,066			29,970
Other fixed assets	116,801			105,075
Construction in progress	281,327			234,646
	4,343,857			3,943,114
Accumulated depreciation	(949,261		)	(748,414		)
	$	3,394,596		$	3,194,700

We capitalized interest attributable to construction projects of $12.1 million, $9.1 million and $17.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Depreciation expense was $213.6 million, $182.9 million and $125.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. For the years ended December 31, 2013, 2012 and 2011, depreciation expense included $62.3 million, $55.5 million and $31.2 million, respectively, attributable to HEP operations.


NOTE 10:	Goodwill

The following table provides a summary of changes to our goodwill balance by segment for the year ended December 31, 2013.



	Refining Segment			HEP		Total
	(In thousands)
Balance at January 1, 2013	$	2,049,311		$	288,991	$	2,338,302
Adjustments to goodwill	(6,380		)	—		(6,380		)
Balance at December 31, 2013	$	2,042,931		$	288,991	$	2,331,922

During 2013, we recorded additional in-process inventory and a corresponding reduction in goodwill to correct immaterial errors related to inventories purchased in previous business combinations.


NOTE 11:	Environmental

We expensed $13.2 million, $46.1 million and $14.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, for environmental remediation obligations. In 2012, we increased certain environmental cost accruals to reflect revisions to certain cost estimates and the time frame for which certain environmental remediation and monitoring activities are expected to occur. The accrued environmental liability reflected in our consolidated balance sheets was $87.8 million and $88.9 million at December 31, 2013 and 2012, respectively, of which $73.6 million and $72.6 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time (up to 30 years for certain projects).

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Continued


NOTE 12:	Debt

HollyFrontier Credit Agreement

We have a $1 billion senior secured credit agreement that matures in July 2016 (the “HollyFrontier Credit Agreement”) and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivable and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2013, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $5.2 million under the HollyFrontier Credit Agreement.

HEP Credit Agreement

In November 2013, HEP amended its senior secured credit agreement increasing the size of the credit facility from $550 million to $650 million (the “HEP Credit Agreement”). The HEP Credit Agreement matures in November 2018 and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit. At December 31, 2013, HEP was in compliance with all its covenants, had outstanding borrowings of $363.0 million and no outstanding letters of credit under the HEP Credit Agreement.

HollyFrontier Senior Notes

In September 2012, we redeemed our $200 million aggregate principal amount of 8.5% senior notes maturing September 2016 at a redemption price of $208.5 million.

HollyFrontier Financing Obligation

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HEP Senior Notes

HEP’s senior notes consist of the following:


•	8.25% HEP senior notes ($150 million principal amount maturing March 2018)


•	6.5% HEP senior notes ($300 million principal amount maturing March 2020)

In March 2012, HEP issued $300 million in an aggregate principal amount of 6.5% HEP senior notes maturing March 2020. The $294.8 million in net proceeds were used to repay $157.8 million aggregate principal amount of 6.25% HEP senior notes, $72.9 million in promissory notes due to HollyFrontier, related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the HEP Credit Agreement. In April 2012, HEP called for redemption the remaining $27.2 million aggregate principal amount outstanding of 6.25% HEP senior notes.

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



	December 31,
	2013		2012
	(In thousands)
9.875% Senior Notes
Principal	$	—	$	286,812
Unamortized discount	—		(7,468		)
	—		279,344
6.875% Senior Notes
Principal	150,000		150,000
Unamortized premium	5,054		5,910
	155,054		155,910
Financing Obligation	34,835		36,311

Total HollyFrontier long-term debt	189,889		471,565

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Continued



	December 31,
	2013			2012
	(In thousands)

HEP Credit Agreement	363,000			421,000

HEP 8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,297		)	(1,602		)
	148,703			148,398
HEP 6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,073		)	(4,725		)
	295,927			295,275

Total HEP long-term debt	807,630			864,673

Total long-term debt	$	997,519		$	1,336,238

Principal maturities of long-term debt are as follows:



Years Ending December 31,	(In thousands)
2014	$	1,666
2015	1,880
2016	2,121
2017	2,393
2018	665,700
Thereafter	324,075
Total	$	997,835


NOTE 13:	Derivative Instruments and Hedging Activities

Commodity Price Risk Management


•	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 and WTI crude oil and forecasted sales of ultra-low sulfur diesel and conventional unleaded gasoline. These contracts have been designated as accounting hedges and are measured quarterly 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. Also 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 under hedge accounting:

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Continued



	Unrealized Gain (Loss) Recognized in OCI			Gain (Loss) Recognized in Earnings Due to Settlements				Gain (Loss) Attributable to Hedge Ineffectiveness Recognized in Earnings
	Unrealized Gain (Loss) Recognized in OCI			Location	Amount			Location	Amount
				(In thousands)
Year Ended December 31, 2013
Commodity price swaps
Change in fair value	$	(8,808	)	Sales and other revenues	$	(20,060	)	Sales and other revenues	$	45
Gain reclassified to earnings due to settlements	(16,410		)	Cost of products sold	38,949			Cost of products sold	515
Amortization of discontinued hedges reclassified to earnings	900			Operating expenses	(3,379		)
Total	$	(24,318	)		$	15,510			$	560

Year Ended December 31, 2012
Commodity price swaps
Change in fair value	$	(248,399	)	Sales and other revenues	$	(98,750	)	Sales and other revenues	$	(491	)
Loss reclassified to earnings due to settlements	55,175			Cost of products sold	43,575			Cost of products sold	(515		)
Total	$	(193,224	)		$	(55,175	)		$	(1,006	)

Year Ended December 31, 2011
Commodity price swaps
Change in fair value	$	173,208
Loss reclassified to earnings due to settlements	166			Operating expenses	$	(166	)	Cost of products sold	$	446
Total	$	173,374			$	(166	)		$	446

As of December 31, 2013, we have the following notional contract volumes related to outstanding derivative instruments serving as cash flow hedges against price risk on forecasted purchases of natural gas and crude oil and sales of refined products:



		Notional Contract Volumes by Year of Maturity
Derivative instruments	Total Outstanding Notional	2014	2015	2016	2017	Unit of Measure

Natural gas - long	38,400,000	9,600,000	9,600,000	9,600,000	9,600,000	MMBTU
WTI crude oil - long	18,797,500	16,242,500	2,555,000	—	—	Barrels
Ultra-low sulfur diesel - short	15,512,500	12,957,500	2,555,000	—	—	Barrels
Sub octane gasoline - short	3,285,000	3,285,000	—	—	—	Barrels

In the first quarter of 2013, we dedesignated certain commodity price swaps (long positions) that previously received hedge accounting treatment. These contracts now serve as economic hedges against price risk on forecasted natural gas purchases totaling 38,400,000 MMBTU's to be purchased ratably through 2017. As of December 31, 2013, we have an unrealized loss of $4.3 million classified in accumulated other comprehensive income that relates to the application of hedge accounting prior to dedesignation that will be amortized as a charge to operating expenses as the contracts mature.

Economic Hedges

We also have swap contracts that serve as economic hedges (derivatives used for risk management, but not designated as accounting hedges) to fix our purchase price on forecasted natural gas purchases, and to lock in the spread between WCS and WTI crude oil on forecasted purchases of WCS. Also, we have NYMEX futures contracts to lock in prices on forecasted purchases of inventory. These contracts are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to income.

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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 Income	2013			2012		2011
	(In thousands)
Cost of products sold	$	20,751		$	12,295	$	3,219
Operating expenses	(5,250		)	573		—
Total	$	15,501		$	12,868	$	3,219

As of December 31, 2013, we have the following notional contract volumes related to our outstanding derivative contracts serving as economic hedges:



		Notional Contract Volumes by Year of Maturity
Derivative Instrument	Total Outstanding Notional	2014	2015	2016	2017	Unit of Measure

Commodity price swap (WCS spread) - long	6,387,500	6,387,500	—	—	—	Barrels
Commodity price swap (natural gas) - long	38,400,000	9,600,000	9,600,000	9,600,000	9,600,000	MMBTU
Commodity price swap (natural gas) - short	38,400,000	9,600,000	9,600,000	9,600,000	9,600,000	MMBTU
NYMEX futures (WTI) - short	1,946,000	1,946,000	—	—	—	Barrels
Physical contracts - long	300,000	300,000	—	—	—	Barrels
Physical contracts - short	300,000	300,000	—	—	—	Barrels

Interest Rate Risk Management

HEP uses interest rate swaps to manage its exposure to interest rate risk.

As of December 31, 2013, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.99%. This swap matures in February 2016. HEP has two additional interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.74%. Both of these swap contracts mature in July 2017. All of these swap contracts have been designated as cash flow hedges. To date, there has been no ineffectiveness on these cash flow hedges.

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Continued

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			Loss Recognized in Earnings Due to Settlements
	Unrealized Gain (Loss) Recognized in OCI			Location	Amount
				(In thousands)
Year Ended December 31, 2013
Interest rate swaps
Change in fair value	$	1,194
Loss reclassified to earnings due to settlements	2,092
Amortization of discontinued hedge reclassified to earnings	849			Interest expense	$	(2,941	)
Total	$	4,135			$	(2,941	)

Year Ended December 31, 2012
Interest rate swaps
Change in fair value	$	(4,418	)
Loss reclassified to earnings due to settlements	1,508
Amortization of discontinued hedge reclassified to earnings	5,095			Interest expense	$	(6,603	)
Total	$	2,185			$	(6,603	)

Year Ended December 31, 2011
Interest rate swaps
Change in fair value	$	(1,956	)
Loss reclassified to earnings due to settlements	5,477
Amortization of discontinued hedge reclassified to earnings	41			Interest expense	$	(5,518	)
Total	$	3,562			$	(5,518	)

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, 2013
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts	$	—	$	—	$	—	$	63,561	$	(23,679	)	$	39,882
Interest rate swap contracts	1,670		—		1,670		1,814		—			1,814
	$	1,670	$	—	$	1,670	$	65,375	$	(23,679	)	$	41,696

Derivatives not designated as cash flow hedging instruments:
Commodity price swap contracts	$	6,972	$	—	$	6,972	$	19,766	$	(12,611	)	$	7,155
NYMEX futures contracts	—		—		—		3,569		—			3,569
	$	6,972	$	—	$	6,972	$	23,335	$	(12,611	)	$	10,724

Total net balance					$	8,642						$	52,420

Balance sheet classification:	Prepayment and other				$	6,972	Accrued liabilities					$	26,843
	Intangibles and other				1,670		Other long-term liabilities					25,577
					$	8,642						$	52,420

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	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, 2012
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts	$	—	$	—	$	—	$	37,828	$	(17,383	)	$	20,445
Interest rate swap contracts	—		—		—		3,430		—			3,430
	$	—	$	—	$	—	$	41,258	$	(17,383	)	$	23,875

Derivatives not designated as cash flow hedging instruments:
Commodity price swap contracts	$	—	$	—	$	—	$	46,154	$	—		$	46,154
NYMEX futures contracts	—		—		—		5,563		—			5,563
	$	—	$	—	$	—	$	51,717	$	—		$	51,717

Total net balance					$	—						$	75,592

Balance sheet classification:							Accrued liabilities					$	62,388
							Other long-term liabilities					13,204
												$	75,592

At December 31, 2013, we had a pre-tax net unrealized loss of $44.3 million classified in accumulated other comprehensive income that relates to all accounting hedges having contractual maturities through 2017. Assuming commodity prices and interest rates remain unchanged, an unrealized loss of $22.2 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 provision for income taxes is comprised of the following:



	Years Ended December 31,
	2013		2012		2011
	(In thousands)
Current
Federal	$	270,024	$	797,406	$	499,535
State	7,148		135,148		91,316
Deferred
Federal	94,896		70,671		(9,679		)
State	19,508		24,737		819
	$	391,576	$	1,027,962	$	581,991

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Continued

The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows:



	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Tax computed at statutory rate	$	405,790		$	975,798		$	574,682
State income taxes, net of federal tax benefit	21,363			110,739			64,284
Domestic production activities deduction	(22,101		)	(54,745		)	(32,194		)
Noncontrolling interest in net income	(12,378		)	(12,783		)	(14,221		)
Uncertain tax positions	(193		)	7,309			(12,125		)
Other	(905		)	1,644			1,565
	$	391,576		$	1,027,962		$	581,991

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, 2013 and 2012 are as follows:



	December 31, 2013
	Assets		Liabilities			Total
	(In thousands)
Deferred income taxes
Accrued employee benefits	$	3,138	$	—		$	3,138
Accrued environmental costs	5,010		—			5,010
Hedging instruments	12,417		—			12,417
Inventory differences	—		(235,823		)	(235,823		)
Prepaid insurance	—		(7,222		)	(7,222		)
Prepayments and other	—		(1,519		)	(1,519		)
Total current	20,565		(244,564		)	(223,999		)
Properties, plants and equipment (due primarily to tax in excess of book depreciation)	—		(578,958		)	(578,958		)
Accrued employee benefits	41,997		—			41,997
Accrued post-retirement benefits	—		(8,071		)	(8,071		)
Accrued environmental costs	20,431		—			20,431
Hedging instruments	3,744		—			3,744
Deferred turnaround costs	—		(101,158		)	(101,158		)
Net operating loss and tax credit carryforwards	24,086		—			24,086
Investment in HEP	—		(29,771		)	(29,771		)
Other	10,858		—			10,858
Total noncurrent	101,116		(717,958		)	(616,842		)
Total	$	121,681	$	(962,522	)	$	(840,841	)

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Continued



	December 31, 2012
	Assets		Liabilities			Total
	(In thousands)
Deferred income taxes
Accrued employee benefits	$	13,285	$	—		$	13,285
Accrued post-retirement benefits	—		(563		)	(563		)
Accrued environmental costs	5,096		—			5,096
Hedging instruments	23,927		—			23,927
Inventory differences	—		(181,634		)	(181,634		)
Prepayments and other	—		(5,327		)	(5,327		)
Total current	42,308		(187,524		)	(145,216		)
Properties, plants and equipment (due primarily to tax in excess of book depreciation)	—		(536,430		)	(536,430		)
Accrued post-retirement benefits	15,628		—			15,628
Accrued environmental costs	18,963		—			18,963
Hedging instruments	3,802		—			3,802
Deferred turnaround costs	—		(60,167		)	(60,167		)
Net operating loss and tax credit carryforwards	21,863		—			21,863
Investment in HEP	—		(15,915		)	(15,915		)
Debt fair value premium	8,820		—			8,820
Other	6,766		—			6,766
Total noncurrent	75,842		(612,512		)	(536,670		)
Total	$	118,150	$	(800,036	)	$	(681,886	)

At December 31, 2013, we had a net operating loss carryforward of $46.2 million in the state of Colorado that is scheduled to be utilized in 2014 through 2029 and a Kansas income tax credit of $12.8 million that is scheduled to be utilized in 2014 through 2019. These amounts are reflected in other current and non-current deferred tax assets.

As of December 31, 2013, the total amount of unrecognized tax benefits was $9.0 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Balance at January 1	$	12,641		$	2,425		$	1,864
Additions due to merger with Frontier	—			—			22,577
Additions for tax positions of prior years	25,728			10,305			73
Reductions for tax positions of prior years	(5,092		)	(89		)	(204		)
Settlements	(24,271		)	—			(21,679		)
Reductions for statute limitations	—			—			(206		)
Balance at December 31	$	9,006		$	12,641		$	2,425

At December 31, 2013, 2012 and 2011, there were $0.4 million, $10.2 million and $2.2 million, respectively, of unrecognized tax benefits that, if recognized, would affect our effective tax rate. 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.

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 expect that unrecognized tax benefits for tax positions taken with respect to 2013 and prior years will change within the next 12 months and the majority of these items will be settled with taxing authorities.

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

We are subject to U.S. federal income tax, Oklahoma, New Mexico, Kansas, Utah, Arizona, Colorado and Iowa income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for tax years through December 31, 2009. In late 2013, the Internal Revenue Service commenced an examination of our U.S. federal tax returns for tax years ended December 31, 2010, 2011 and 2012. We anticipate that these audits will be completed in 2014.


NOTE 15:	Stockholders' Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2013, 2012 and 2011 are presented below:



	Years Ended December 31,
	2013		2012		2011
	(In thousands)
Common shares outstanding at January 1	203,551,496		209,332,646		106,529,376
Common shares issued in connection with merger with Frontier	—		—		103,270,002
Issuance of restricted stock, excluding restricted stock with performance feature	292,855		691,207		512,880
Vesting of performance units	210,819		869,231		233,134
Vesting of restricted stock with performance feature	15,141		146,400		124,332
Forfeitures of restricted stock	(15,794	)	(3,975	)	(3,730	)
Purchase of treasury stock ⁽¹⁾	(5,224,166	)	(7,484,013	)	(1,333,348	)
Common shares outstanding at December 31	198,830,351		203,551,496		209,332,646


(1)	Includes 235,922, 560,484 and 747,225 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.

We have a Board approved repurchase program that authorizes 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, corporate, regulatory and other relevant considerations. This program may be discontinued at any time by the Board of Directors. As of December 31, 2013, we had remaining authorization to repurchase up to $311.6 million under this stock repurchase program.

In May 2012, we entered into a structured share repurchase arrangement with a financial institution under which we provided an up-front cash payment of $100.0 million and, depending on market conditions, would either receive shares of our common stock or cash at the expiration of the agreement. The agreement expired in September 2012 at which time we received our up-front payment plus an additional $8.6 million in cash that was recorded as additional capital.

During the years ended December 31, 2013, 2012 and 2011, we withheld shares of our common stock from certain employees in the amounts of $11.3 million, $22.4 million and $24.9 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


NOTE 16:	Other Comprehensive Income (Loss)

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



	Before-Tax			Tax Expense (Benefit)			After-Tax
	(In thousands)
Year Ended December 31, 2013
Net unrealized gain on marketable securities	$	34		$	17		$	17
Net unrealized loss on hedging instruments	(20,183		)	(8,669		)	(11,514		)
Net change in pension and other post-retirement benefit obligations	37,593			14,534			23,059
Other comprehensive income	17,444			5,882			11,562
Less other comprehensive income attributable to noncontrolling interest	2,315			—			2,315
Other comprehensive income attributable to HollyFrontier stockholders	$	15,129		$	5,882		$	9,247

Year Ended December 31, 2012
Net unrealized loss on marketable securities	$	(236	)	$	(95	)	$	(141	)
Net unrealized loss on hedging instruments	(191,039		)	(74,846		)	(116,193		)
Net change in pension and other post-retirement benefit obligations	51,391			19,991			31,400
Other comprehensive loss	(139,884		)	(54,950		)	(84,934		)
Less other comprehensive income attributable to noncontrolling interest	1,364			—			1,364
Other comprehensive loss attributable to HollyFrontier stockholders	$	(141,248	)	$	(54,950	)	$	(86,298	)

Year Ended December 31, 2011
Net unrealized loss on marketable securities	$	(516	)	$	(199	)	$	(317	)
Net unrealized gain on hedging instruments	176,936			67,732			109,204
Net change in pension and other post-retirement benefit obligations	(3,586		)	(1,395		)	(2,191		)
Other comprehensive income	172,834			66,138			106,696
Less other comprehensive income attributable to noncontrolling interest	2,815			—			2,815
Other comprehensive income attributable to HollyFrontier stockholders	$	170,019		$	66,138		$	103,881

The temporary unrealized gain (loss) on marketable securities is due to changes in market prices.

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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
	(In thousands)
	Years Ended December 31,
	2013			2012			2011
Marketable securities	$	39		$	59		$	(14	)	Interest income
	—			326			—			Gain on sale of marketable equity securities
	39			385			(14		)
	15			150			(5		)	Income tax expense (benefit)
	24			235			(9		)	Net of tax

Hedging instruments:
Commodity price swaps	(20,060		)	(98,750		)	—			Sales and other revenues
	38,949			43,575			—			Cost of products sold
	(3,379		)	—			(166		)	Operating expenses
Interest rate swaps	(2,941		)	(6,603		)	(5,518		)	Interest expense
	12,569			(61,778		)	(5,684		)
	5,554			(22,590		)	(961		)	Income tax expense (benefit)
	7,015			(39,188		)	(4,723		)	Net of tax
	1,783			3,753			3,214			Noncontrolling interest
	8,798			(35,435		)	(1,509		)	Net of tax and noncontrolling interest

Pension and other post-retirement benefit obligations:
Pension obligation	(3,226		)	(226		)	(155		)	Cost of products sold
	(30,127		)	(1,486		)	(1,056		)	Operating expenses
	(4,236		)	(244		)	(1,091		)	General and administrative expenses
	(37,589		)	(1,956		)	(2,302		)
	(14,547		)	(761		)	(895		)	Income tax benefit
	(23,042		)	(1,195		)	(1,407		)	Net of tax

Post-retirement healthcare obligation	646			—			(16		)	Cost of products sold
	2,868			1,913			(125		)	Operating expenses
	526			39			(17		)	General and administrative expenses
	4,040			1,952			(158		)
	1,563			759			(61		)	Income tax expense (benefit)
	2,477			1,193			(97		)	Net of tax

Retirement restoration plan	(111		)	(63		)	(99		)	General and administrative expenses
	(43		)	(25		)	(39		)	Income tax benefit
	(68		)	(38		)	(60		)	Net of tax

Total reclassifications for the period	$	(11,811	)	$	(35,240	)	$	(3,082	)

Accumulated other comprehensive income (loss) in the equity section of our consolidated balance sheets includes:



	December 31,
	2013			2012
	(In thousands)
Unrealized gain on post-retirement benefit obligations	$	27,691		$	4,632
Unrealized gain (loss) on marketable securities	10			(7		)
Unrealized loss on hedging instruments, net of noncontrolling interest	(26,879		)	(13,050		)
Accumulated other comprehensive income (loss)	$	822		$	(8,425	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


NOTE 17:	Retirement Plan

In 2012, our Compensation Committee, pursuant to authority delegated to it by the Board of Directors, approved the termination of the HollyFrontier Corporation Pension Plan (the "Plan"), a non-contributory defined benefit retirement plan that covered certain employees and was fully frozen prior to 2013.

In June 2013, we made contributions of $22.7 million to the Plan, which was sufficient for the Plan to settle its obligations to all participants including the premium paid to the non-participating annuity provider. In 2013, we recognized a pre-tax pension settlement charge of $39.5 million, of which $37.6 million was reclassified out of accumulated other comprehensive income, representing the irrevocable portion of our obligation.

The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2013 and 2012:



	Years Ended December 31,
	2013			2012
	(In thousands)
Change in plan's benefit obligation
Pension plan's benefit obligation - beginning of year	$	95,485		$	93,378
Service cost	—			679
Interest cost	1,797			3,962
Benefits paid	(3,957		)	(1,379		)
Actuarial loss	2,981			13,203
Settlements paid	(96,306		)	(7,256		)
Curtailment	—			(7,102		)
Pension plan's benefit obligation - end of year	$	—		$	95,485

Change in pension plan assets
Fair value of plan assets - beginning of year	$	77,757		$	61,398
Actual return on plan assets	(219		)	2,615
Benefits paid	(3,957		)	(1,379		)
Employer contributions	22,725			22,379
Settlements paid	(96,306		)	(7,256		)
Fair value of plan assets - end of year	$	—		$	77,757

Funded status
Under-funded balance	$	—		$	(17,728	)

Amounts recognized in consolidated balance sheets
Accrued pension liability	$	—		$	(17,728	)

Amounts recognized in accumulated other comprehensive income (loss)
Cumulative actuarial loss	$	—		$	(37,589	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

Net periodic pension expense consisted of the following components:



	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Service cost – benefit earned during the year	$	—		$	679		$	5,070
Interest cost on projected benefit obligations	1,797			3,962			5,125
Expected return on plan assets	(92		)	(3,798		)	(5,230		)
Amortization of prior service cost	—			67			390
Amortization of net loss	1,386			1,933			2,126
Curtailment	—			899			1,065
Loss on settlement	36,203			2,855			3,951
Loss on plan termination	3,293			—			—
Net periodic pension expense	$	42,587		$	6,597		$	12,497

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



	December 31,
	2013		2012		2011

Discount rate	3.95	%	4.60	%	5.65	%
Rate of future compensation increases	—	%	4.00	%	4.00	%
Expected long-term rate of return on assets	0.25	%	6.50	%	8.00	%

In 2012, we established a program for plan participants whose benefits pursuant to the defined benefit plan were frozen. The program provides for payments after year-end for three years (beginning with 2012) provided the employee is employed by us on the last day of each year. The payments are based on each employee's years of service and eligible salary. Transition benefit costs associated with transition to the new defined contribution plan were $12.5 million and $15.6 million for the years ended December 31, 2013 and 2012, respectively.

Post-retirement Healthcare Plans

We provide post-retirement medical benefits to certain eligible employees. These plans are unfunded and provide differing levels of healthcare benefits dependent upon hire date and work location. Not all of our employees are covered by these plans at December 31, 2013.

Effective December 31, 2012, we amended the post-retirement healthcare plans for participants retiring after December 31, 2012 by eliminating post-retirement benefits after reaching age 65 and eliminating early retirement benefits for most participants who retire before reaching age 62. In addition, certain future retirees will receive a cash payment in lieu of post-retirement benefits after reaching age 65 and other changes were made generally to conform benefits. In the first quarter of 2013, we settled a portion of our post-retirement medical obligation, at which time we reclassified a $1.7 million pretax loss out of accumulated other comprehensive income that was recognized as a charge to net income.

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

The following table sets forth the changes in the benefit obligation and plan assets of our post-retirement healthcare plans for the years ended December 31, 2013 and 2012:



	Years Ended December 31,
	2013			2012
	(In thousands)
Change in plans' benefit obligation
Post-retirement plans' benefit obligation - beginning of year	$	26,797		$	77,303
Service cost	1,112			1,892
Interest cost	665			3,519
Participant contributions	564			760
Amendments	(820		)	(49,399		)
Settlements	(8,627		)	—
Benefits paid	(1,585		)	(1,275		)
Actuarial gain	(2,391		)	(6,003		)
Post-retirement plans' benefit obligation - end of year	$	15,715		$	26,797

Change in plan assets
Fair value of plan assets - beginning of year	$	—		$	—
Employer contributions	9,648			515
Participant contributions	564			760
Settlements	(8,627		)	—
Benefits paid	(1,585		)	(1,275		)
Fair value of plan assets - end of year	$	—		$	—

Funded status
Under-funded balance	$	(15,715	)	$	(26,797	)

Amounts recognized in consolidated balance sheets
Accrued post-retirement liability	$	(15,715	)	$	(26,797	)

Amounts recognized in accumulated other comprehensive income (loss)
Cumulative actuarial loss	$	(1,022	)	$	(5,359	)
Prior service credit	47,098			52,174
Total	$	46,076		$	46,815

Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.4 million in 2014; $1.2 million in 2015; $1.2 million in 2016; $1.2 million in 2017; $1.3 million in 2018; and $6.6 million in 2019 through 2023.

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



	December 31,
	2013		2012

Discount rate	4.25	%	3.45	%
Current health care trend rate	8.00	%	8.10	%
Ultimate health care trend rate	5.00	%	5.00	%
Year rate reaches ultimate trend rate	2045		2023

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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



	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Service cost – benefit earned during the year	$	1,112		$	1,892		$	1,569
Interest cost on projected benefit obligations	665			3,519			2,193
Amortization of transition obligation	—			—			44
Amortization of prior service credit	(5,896		)	(2,221		)	—
Amortization of net loss	130			269			114
Loss on settlement	1,726			—			—
Net periodic post-retirement expense (credit)	$	(2,263	)	$	3,459		$	3,920

Assumed health care cost trend rates have an effect on the amounts reported for the post-retirement health care benefit plans. The weighted average assumptions used to determine net periodic benefit expense follow:



	Years Ended December 31,
	2013		2012		2011

Discount rate	3.45	%	4.60	%	5.75	%
Current health care trend rate	8.10	%	8.40	%	8.70	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year rate reaches ultimate trend rate	2023		2023		2023

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	$	241	$	(197	)
Interest cost	$	60	$	(50	)
Year-end accumulated post-retirement benefit obligation	$	1,373	$	(1,109	)

Retirement Restoration Plan

We adopted 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. Effective January 1, 2012, we ceased to accrue benefits under this plan. We expensed $0.4 million, $0.3 million and $0.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.8 million and $7.4 million at December 31, 2013 and 2012, respectively. As of December 31, 2013, the projected benefit obligation under this plan was $6.8 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $2.3 million in 2014; $0.5 million in 2015; $0.5 million in 2016; $1.6 million in 2017; $0.3 million in 2018; and $1.3 million in 2019 through 2023.

Defined Contribution Plans

We have a defined contribution “401(k)” plan that covers substantially all employees. Our contributions are based on an employee's eligible compensation and years of service. We also partially match the employee's contributions. We expensed $15.5 million, $16.0 million and $9.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, in connection with these plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


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, 2013, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows:



	(In thousands)
2014	$	23,709
2015	22,139
2016	20,189
2017	11,974
2018	4,965
Thereafter	4,825
Total	$	87,801

Rental expense charged to operations was $48.5 million, $42.6 million and $35.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. For the years ended December 31, 2013, 2012 and 2011, rental expense included $8.3 million, $8.1 million and $7.5 million attributable to the HEP operations.


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 2014 through 2020.

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 2014 through 2032. At December 31, 2013, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:



	(In thousands)
2014	$	144,434
2015	143,747
2016	121,557
2017	111,131
2018	93,884
Thereafter	659,324
Total	$	1,274,077

Transportation and storage costs incurred under these agreements totaled $122.0 million for the year ended December 31, 2013. These amounts do not include contractual commitments under our long-term transportation agreements with HEP. HEP is a consolidated VIE; all transactions with HEP are eliminated in these consolidated financial statements.

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


NOTE 20:	Segment Information

Our operations are organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.

The Refining segment represents the operations of the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK 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. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refineries that are marketed throughout North America and are distributed in Central and South America. NK Asphalt operates various asphalt terminals in Arizona and New Mexico.

The HEP segment includes all of the operations of HEP, a consolidated VIE, which owns and operates logistics assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. The HEP segment also includes a 75% interest in UNEV (a consolidated subsidiary of HEP) and a 25% interest in the SLC 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		HEP		Corporate and Other			Consolidations and Eliminations			Consolidated Total
	(In thousands)
Year Ended December 31, 2013
Sales and other revenues	$	20,105,443	$	307,053	$	1,314		$	(253,250	)	$	20,160,560
Depreciation and amortization	$	233,182	$	64,701	$	6,391		$	(828	)	$	303,446
Income (loss) from operations	$	1,237,687	$	133,522	$	(123,030	)	$	(2,105	)	$	1,246,074
Capital expenditures	$	344,113	$	51,856	$	29,158		$	—		$	425,127
Total assets	$	7,094,558	$	1,413,908	$	1,881,119		$	(332,846	)	$	10,056,739

Year Ended December 31, 2012
Sales and other revenues	$	20,042,955	$	288,501	$	1,048		$	(241,780	)	$	20,090,724
Depreciation and amortization	$	181,247	$	57,789	$	4,660		$	(828	)	$	242,868
Income (loss) from operations	$	2,879,383	$	133,723	$	(126,840	)	$	(2,120	)	$	2,884,146
Capital expenditures	$	278,705	$	44,929	$	11,629		$	—		$	335,263
Total assets	$	6,702,872	$	1,426,800	$	2,531,967		$	(332,642	)	$	10,328,997

Year Ended December 31, 2011
Sales and other revenues	$	15,392,430	$	212,995	$	1,098		$	(166,995	)	$	15,439,528
Depreciation and amortization	$	122,437	$	33,288	$	4,810		$	(828	)	$	159,707
Income (loss) from operations	$	1,739,068	$	110,102	$	(117,677	)	$	55		$	1,731,548
Capital expenditures	$	148,699	$	216,215	$	9,327		$	—		$	374,241
Total assets	$	6,576,966	$	1,418,660	$	1,997,600		$	(416,983	)	$	9,576,243

HEP segment revenues from external customers were $53.4 million, $47.6 million and $46.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.


NOTE 21:	Supplemental Guarantor/Non-Guarantor Financial Information

Our obligations under the HollyFrontier Senior Notes have been jointly and severally guaranteed by the substantial majority of our existing and future restricted subsidiaries (“Guarantor Restricted Subsidiaries”). These guarantees are full and unconditional. HEP, in which we have a 39% ownership interest at December 31, 2013, and its subsidiaries (collectively, “Non-Guarantor Non-Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed these obligations.

The following condensed consolidating financial information is provided for HollyFrontier Corporation (the “Parent”), the Guarantor Restricted Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Restricted Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the Non-Guarantor Restricted Subsidiaries are collectively the “Restricted Subsidiaries.”

Certain reclassifications have been made to intercompany balances in our prior year condensed parent company balance sheet to conform with our current year presentation. Additionally, we have made certain revisions to our prior year condensed statements of cash flows to reclassify intercompany lending and distribution activity between operating, investing and financing activities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Balance Sheet
December 31, 2013	Parent		Guarantor Restricted Subsidiaries		Non- Guarantor Restricted Subsidiaries		Eliminations			HollyFrontier Corp. Before Consolidation of HEP		Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)		Consolidations and Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	931,920	$	1,817	$	14	$	—		$	933,751	$	6,352	$	—		$	940,103
Marketable securities	725,160		—		—		—			725,160		—		—			725,160
Accounts receivable, net	6,095		698,109		8,075		—			712,279		34,736		(38,213		)	708,802
Intercompany accounts receivable	—		149,907		313,623		(463,530		)	—		—		—			—
Inventories	—		1,352,656		—		—			1,352,656		1,591		—			1,354,247
Income taxes receivable	109,376		—		—		—			109,376		—		—			109,376
Prepayments and other	21,843		45,413		—		—			67,256		2,283		(10,783		)	58,756
Total current assets	1,794,394		2,247,902		321,712		(463,530		)	3,900,478		44,962		(48,996		)	3,896,444
Properties, plants and equip, net	30,007		2,633,739		24		—			2,663,770		1,004,975		(274,149		)	3,394,596
Investment in subsidiaries	5,722,025		216,687		—		(5,938,712		)	—		—		—			—
Intangibles and other assets	23,034		2,380,268		25,000		(25,000		)	2,403,302		363,970		(1,573		)	2,765,699
Total assets	$	7,569,460	$	7,478,596	$	346,736	$	(6,427,242	)	$	8,967,550	$	1,413,907	$	(324,718	)	$	10,056,739

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	16,704	$	1,323,603	$	383	$	—		$	1,340,690	$	22,898	$	(38,212	)	$	1,325,376
Intercompany accounts payable	463,530		—		—		(463,530		)	—		—		—			—
Accrued liabilities	43,254		63,181		795		—			107,230		28,668		(10,783		)	125,115
Deferred income tax liabilities	223,999		—		—		—			223,999		—		—			223,999
Total current liabilities	747,487		1,386,784		1,178		(463,530		)	1,671,919		51,566		(48,995		)	1,674,490
Long-term debt	180,054		34,835		—		(25,000		)	189,889		807,630		—			997,519
Liability to HEP	—		245,536		—		—			245,536		—		(245,536		)	—
Deferred income tax liabilities	611,555		—		—		—			611,555		5,287		—			616,842
Other long-term liabilities	35,874		89,416		—		—			125,290		35,918		(2,718		)	158,490
Investment in HEP	—		—		128,871		—			128,871		—		(128,871		)	—
Equity – HollyFrontier	5,994,490		5,722,025		216,687		(5,938,712		)	5,994,490		416,018		(410,888		)	5,999,620
Equity – noncontrolling interest	—		—		—		—			—		97,488		512,290			609,778
Total liabilities and equity	$	7,569,460	$	7,478,596	$	346,736	$	(6,427,242	)	$	8,967,550	$	1,413,907	$	(324,718	)	$	10,056,739

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Balance Sheet
December 31, 2012	Parent		Guarantor Restricted Subsidiaries		Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP		Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)		Consolidations and Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,748,808	$	3,652	$	2		$	—		$	1,752,462	$	5,237	$	—		$	1,757,699
Marketable securities	630,579		7		—			—			630,586		—		—			630,586
Accounts receivable, net	4,788		627,262		—			—			632,050		38,097		(35,917		)	634,230
Intercompany accounts receivable	—		285,291		261,364			(546,655		)	—		—		—			—
Inventories	—		1,318,373		—			—			1,318,373		1,259		—			1,319,632
Income taxes receivable	74,957		—		—			—			74,957		—		—			74,957
Prepayments and other	21,867		34,667		—			—			56,534		2,360		(5,733		)	53,161
Total current assets	2,480,999		2,269,252		261,366			(546,655		)	4,464,962		46,953		(41,650		)	4,470,265
Properties, plants and equip, net	24,209		2,444,398		—			—			2,468,607		1,014,556		(288,463		)	3,194,700
Marketable securities (long-term)	5,116		—		—			—			5,116		—		—			5,116
Investment in subsidiaries	5,251,396		74,120		—			(5,325,516		)	—		—		—			—
Intangibles and other assets	11,825		2,284,329		25,000			(25,000		)	2,296,154		365,291		(2,529		)	2,658,916
Total assets	$	7,773,545	$	7,072,099	$	286,366		$	(5,897,171	)	$	9,234,839	$	1,426,800	$	(332,642	)	$	10,328,997

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,941	$	1,336,097	$	—		$	—		$	1,338,038	$	12,030	$	(35,917	)	$	1,314,151
Intercompany accounts payable	546,655		—		—			(546,655		)	—		—		—			—
Accrued liabilities	71,226		105,298		581			—			177,105		23,705		(5,733		)	195,077
Deferred income tax liabilities	145,225		—		(9		)	—			145,216		—		—			145,216
Total current liabilities	765,047		1,441,395		572			(546,655		)	1,660,359		35,735		(41,650		)	1,654,444
Long-term debt	460,254		36,311		—			(25,000		)	471,565		864,673		—			1,336,238
Liability to HEP	—		257,777		—			—			257,777		—		(257,777		)	—
Deferred income tax liabilities	530,544		—		1,175			—			531,719		—		4,951			536,670
Other long-term liabilities	48,757		85,220		—			—			133,977		28,683		(3,673		)	158,987
Investment in HEP	—		—		210,499			—			210,499		—		(210,499		)	—
Equity – HollyFrontier	5,968,943		5,251,396		74,120			(5,325,516		)	5,968,943		382,207		(298,196		)	6,052,954
Equity – noncontrolling interest	—		—		—			—			—		115,502		474,202			589,704
Total liabilities and equity	$	7,773,545	$	7,072,099	$	286,366		$	(5,897,171	)	$	9,234,839	$	1,426,800	$	(332,642	)	$	10,328,997

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries		Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Consolidations and Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	878		$	20,105,726	$	153		$	—		$	20,106,757		$	307,053		$	(253,250	)	$	20,160,560
Operating costs and expenses:
Cost of products sold	—			17,641,119		—			—			17,641,119			—			(248,892		)	17,392,227
Operating expenses	—			995,194		—			—			995,194			97,081			(1,425		)	1,090,850
General and administrative	113,231			2,752		231			—			116,214			11,749			—			127,963
Depreciation and amortization	5,548			247,514		—			—			253,062			64,701			(14,317		)	303,446
Total operating costs and expenses	118,779			18,886,579		231			—			19,005,589			173,531			(264,634		)	18,914,486
Income (loss) from operations	(117,901		)	1,219,147		(78		)	—			1,101,168			133,522			11,384			1,246,074
Other income (expense):
Earnings (loss) of equity method investments	1,280,868			52,752		57,186			(1,338,518		)	52,288			2,826			(57,186		)	(2,072		)
Interest income (expense)	(15,849		)	8,969		542			—			(6,338		)	(46,849		)	(9,307		)	(62,494		)
Loss on early extinguishment of debt	(22,109		)	—		—			—			(22,109		)	—			—			(22,109		)
	1,242,910			61,721		57,728			(1,338,518		)	23,841			(44,023		)	(66,493		)	(86,675		)
Income before income taxes	1,125,009			1,280,868		57,650			(1,338,518		)	1,125,009			89,499			(55,109		)	1,159,399
Income tax provision	391,243			—		—			—			391,243			333			—			391,576
Net income	733,766			1,280,868		57,650			(1,338,518		)	733,766			89,166			(55,109		)	767,823
Less net income attributable to noncontrolling interest	—			—		—			—			—			6,632			25,349			31,981
Net income attributable to HollyFrontier stockholders	$	733,766		$	1,280,868	$	57,650		$	(1,338,518	)	$	733,766		$	82,534		$	(80,458	)	$	735,842
Comprehensive income attributable to HollyFrontier stockholders	$	743,013		$	1,258,370	$	59,470		$	(1,317,840	)	$	743,013		$	84,354		$	(82,278	)	$	745,089



Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries		Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Consolidations and Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	494		$	20,043,335		$	174	$	—		$	20,044,003		$	288,501		$	(241,780	)	$	20,090,724
Operating costs and expenses:
Cost of products sold	—			16,078,948			—		—			16,078,948			—			(238,305		)	15,840,643
Operating expenses	—			906,098			—		—			906,098			89,395			(527		)	994,966
General and administrative	118,860			1,519			128		—			120,507			7,594			—			128,101
Depreciation and amortization	4,172			181,735			—		—			185,907			57,789			(828		)	242,868
Total operating costs and expenses	123,032			17,168,300			128		—			17,291,460			154,778			(239,660		)	17,206,578
Income (loss) from operations	(122,538		)	2,875,035			46		—			2,752,543			133,723			(2,120		)	2,884,146
Other income (expense):
Earnings of equity method investments	2,921,077			49,347			49,066		(2,970,865		)	48,625			3,364			(49,066		)	2,923
Interest income (expense)	(41,564		)	(3,631		)	676		—			(44,519		)	(57,219		)	2,338			(99,400		)
Gain on sale of marketable securities	—			326			—		—			326			—			—			326
	2,879,513			46,042			49,742		(2,970,865		)	4,432			(53,855		)	(46,728		)	(96,151		)
Income before income taxes	2,756,975			2,921,077			49,788		(2,970,865		)	2,756,975			79,868			(48,848		)	2,787,995
Income tax provision	1,027,591			—			—		—			1,027,591			371			—			1,027,962
Net income	1,729,384			2,921,077			49,788		(2,970,865		)	1,729,384			79,497			(48,848		)	1,760,033
Less net income attributable to noncontrolling interest	—			—			—		—			—			1,153			31,708			32,861
Net income attributable to HollyFrontier stockholders	$	1,729,384		$	2,921,077		$	49,788	$	(2,970,865	)	$	1,729,384		$	78,344		$	(80,556	)	$	1,727,172
Comprehensive income attributable to HollyFrontier stockholders	$	1,643,086		$	2,728,675		$	50,610	$	(2,779,285	)	$	1,643,086		$	79,166		$	(81,378	)	$	1,640,874

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Consolidations and Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	1,008		$	15,392,446		$	74		$	—		$	15,393,528		$	212,995		$	(166,995	)	$	15,439,528
Operating costs and expenses:
Cost of products sold	—			12,844,333			—			—			12,844,333			—			(164,255		)	12,680,078
Operating expenses	—			687,381			(362		)	—			687,019			63,029			(1,967		)	748,081
General and administrative	111,093			2,445			—			—			113,538			6,576			—			120,114
Depreciation and amortization	4,165			123,082			—			—			127,247			33,288			(828		)	159,707
Total operating costs and expenses	115,258			13,657,241			(362		)	—			13,772,137			102,893			(167,050		)	13,707,980
Income (loss) from operations	(114,250		)	1,735,205			436			—			1,621,391			110,102			55			1,731,548
Other income (expense):
Earnings of equity method investments	1,771,022			38,546			38,308			(1,809,820		)	38,056			2,552			(38,308		)	2,300
Interest income (expense)	(38,619		)	(2,729		)	54			—			(41,294		)	(38,209		)	2,464			(77,039		)
Merger transaction costs	(15,114		)	—			—			—			(15,114		)	—			—			(15,114		)
	1,717,289			35,817			38,362			(1,809,820		)	(18,352		)	(35,657		)	(35,844		)	(89,853		)
Income before income taxes	1,603,039			1,771,022			38,798			(1,809,820		)	1,603,039			74,445			(35,789		)	1,641,695
Income tax provision	581,757			—			—			—			581,757			234			—			581,991
Net income	1,021,282			1,771,022			38,798			(1,809,820		)	1,021,282			74,211			(35,789		)	1,059,704
Less net income attributable to noncontrolling interest	—			—			—			—			—			(859		)	37,166			36,307
Net income attributable to HollyFrontier stockholders	$	1,021,282		$	1,771,022		$	38,798		$	(1,809,820	)	$	1,021,282		$	75,070		$	(72,955	)	$	1,023,397
Comprehensive income attributable to HollyFrontier stockholders	$	1,125,163		$	1,945,142		$	39,544		$	(1,984,686	)	$	1,125,163		$	75,816		$	(73,701	)	$	1,127,278

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Consolidations and Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities (1)	$	448,297		$	1,044,492		$	70,977		$	(805,981	)	$	757,785		$	182,799		$	(71,410	)	$	869,174

Cash flow from investing activities
Additions to properties, plants and equipment	(11,727		)	(361,520		)	(24		)	—			(373,271		)	—			—			(373,271		)
Additions to properties, plants and equipment – HEP	—			—			—			—			—			(51,856		)	—			(51,856		)
Acquisition of trucking operations	—			(11,301		)	—			—			(11,301		)	—			—			(11,301		)
Proceeds from sale of property and equipment	—			5,071			—			—			5,071			2,731			—			7,802
Investment in Sabine Biofuels	—			(3,000		)	—			—			(3,000		)	—			—			(3,000		)
Net advances to Sabine Biofuels	—			(5,740		)	—			—			(5,740		)	—			—			(5,740		)
Purchases of marketable securities	(935,512		)	—			—			—			(935,512		)	—			—			(935,512		)
Sales and maturities of marketable securities	846,135			8			—			—			846,143			—			—			846,143
Net intercompany advances (1)	—			137,613			(69,442		)	(68,171		)	—			—			—			—
	(101,104		)	(238,869		)	(69,466		)	(68,171		)	(477,610		)	(49,125		)	—			(526,735		)
Cash flows from financing activities
Net repayments under credit agreement – HEP	—			—			—			—			—			(58,000		)	—			(58,000		)
Redemption of senior notes	(300,973		)	—			—			—			(300,973		)	—			—			(300,973		)
Proceeds from common unit offerings - HEP	73,444			—			—			—			73,444			73,444			—			146,888
Purchase of treasury stock	(225,023		)	—			—			—			(225,023		)	—			—			(225,023		)
Contribution from general partner	—			—			(1,499		)	—			(1,499		)	1,499			—			—
Dividends	(645,920		)	—			—			—			(645,920		)	—			—			(645,920		)
Distributions to noncontrolling interest	—			—			—			—			—			(142,611		)	71,410			(71,201		)
Excess tax benefit from equity-based compensation	2,562			—			—			—			2,562			—			—			2,562
Purchase of units for incentive grants - HEP	—			—			—			—			—			(5,313		)	—			(5,313		)
Deferred financing costs and other	—			(1,477		)	—			—			(1,477		)	(1,578		)	—			(3,055		)
Net repayment of intercompany advances (1)	(68,171		)	—			—			68,171			—			—			—			—
Distributions to Parent (1)	—			(805,981		)	—			805,981			—			—			—			—
	(1,164,081		)	(807,458		)	(1,499		)	874,152			(1,098,886		)	(132,559		)	71,410			(1,160,035		)
Cash and cash equivalents
Increase (decrease) for the period	(816,888		)	(1,835		)	12			—			(818,711		)	1,115			—			(817,596		)
Beginning of period	1,748,808			3,652			2			—			1,752,462			5,237			—			1,757,699
End of period	$	931,920		$	1,817		$	14		$	—		$	933,751		$	6,352		$	—		$	940,103

(1) Parent operating cash flows includes cash inflows of $806.0 million, $2,727.6 million and $2,147.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, representing distributions of earnings from the Restricted Subsidiaries.

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Consolidations and Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities (1)	$	1,571,928		$	2,656,514		$	63,759		$	(2,727,561	)	$	1,564,640		$	162,036		$	(63,989	)	$	1,662,687

Cash flows from investing activities:
Additions to properties, plants and equipment	(7,965		)	(282,369		)	—			—			(290,334		)	—			—			(290,334		)
Additions to properties, plants and equipment – HEP	—			—			—			—			—			(44,929		)	—			(44,929		)
Investment in Sabine Biofuels	—			(2,000		)	—			—			(2,000		)	—			—			(2,000		)
Purchases of marketable securities	(671,552		)	—			—			—			(671,552		)	—			—			(671,552		)
Payments received on promissory notes	—			—			72,900			—			72,900			(72,900		)	—			—
Sales and maturities of marketable securities	296,780			931			—			—			297,711			—			—			297,711
Net intercompany advances (1)	—			101,943			(126,373		)	24,430			—			—			—			—
	(382,737		)	(181,495		)	(53,473		)	24,430			(593,275		)	(117,829		)	—			(711,104		)
Cash flows from financing activities:
Net borrowings under credit agreement – HEP	—			—			—			—			—			221,000			—			221,000
Net proceeds from issuance of senior notes - HEP	—			—			—			—			—			294,750			—			294,750
Redemption of senior notes	(205,000		)	—			—			—			(205,000		)	—			—			(205,000		)
Principal tender on senior notes	—			—			—			—			—			(185,000		)	—			(185,000		)
Purchase of treasury stock	(209,600		)	—			—			—			(209,600		)	—			—			(209,600		)
Structured stock repurchase arrangement	8,620			—			—			—			8,620			—			—			8,620
Contribution from general partner	—			—			(10,286		)	—			(10,286		)	10,286			—			—
Contribution from joint venture partner	—			—			—			—			—			6,000			—			6,000
Distribution from HEP upon UNEV transfer	—			260,922			—			—			260,922			(260,922		)	—			—
Dividends	(658,085		)	—			—			—			(658,085		)	—			—			(658,085		)
Distributions to noncontrolling interest	—			—			—			—			—			(122,777		)	63,989			(58,788		)
Excess tax benefit from equity-based compensation	23,361			—			—			—			23,361			—			—			23,361
Purchase of units for incentive grants - HEP	—			—			—			—			—			(5,240		)	—			(5,240		)
Deferred financing costs and other	—			(1,370		)	—			—			(1,370		)	(3,436		)	—			(4,806		)
Net receipt of intercompany advances (1)	24,430			—			—			(24,430		)	—			—			—			—
Distributions to Parent (1)	—			(2,727,561		)	—			2,727,561			—			—			—			—
	(1,016,274		)	(2,468,009		)	(10,286		)	2,703,131			(791,438		)	(45,339		)	63,989			(772,788		)
Cash and cash equivalents
Increase (decrease) for the period:	172,917			7,010			—			—			179,927			(1,132		)	—			178,795
Beginning of period	1,575,891			(3,358		)	2			—			1,572,535			6,369			—			1,578,904
End of period	$	1,748,808		$	3,652		$	2		$	—		$	1,752,462		$	5,237		$	—		$	1,757,699

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Consolidations and Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities (1)	$	2,275,784		$	1,099,072		$	41,866		$	(2,147,006	)	$	1,269,716		$	108,948		$	(40,273	)	$	1,338,391

Cash flows from investing activities:
Additions to properties, plants and equipment	(7,585		)	(150,441		)	—			—			(158,026		)	—			—			(158,026		)
Additions to properties, plants and equipment – HEP	—			—			—			—			—			(216,215		)	—			(216,215		)
Increase in cash due to merger with Frontier	182			872,557			—			—			872,739			—			—			872,739
Investment in Sabine Biofuels	(9,125		)	—			—			—			(9,125		)	—			—			(9,125		)
Payments received on promissory notes	—			—			77,100			—			77,100			(77,100		)	—			—
Purchases of marketable securities	(561,899		)	—			—			—			(561,899		)	—			—			(561,899		)
Sales and maturities of marketable securities	301,020			—			—			—			301,020			—			—			301,020
Net intercompany advances (1)	—			332,655			9,921			(342,576		)	—			—			—			—
	(277,407		)	1,054,771			87,021			(342,576		)	521,809			(293,315		)	—			228,494
Cash flows from financing activities:
Net borrowings under credit agreement – HEP	—			—			—			—			—			41,000			—			41,000
Proceeds from issuance of common units – HEP	—			—			—			—			—			75,815			—			75,815
Purchase of treasury stock	(42,795		)	—			—			—			(42,795		)	—			—			(42,795		)
Redemptions of senior notes	(8,203		)	—			—			—			(8,203		)	—			—			(8,203		)
Contribution from general partner	—			—			(128,887		)	—			(128,887		)	128,887			—			—
Contribution from joint venture partner	—			—			—			—			—			33,500			—			33,500
Dividends	(252,133		)	—			—			—			(252,133		)	—			—			(252,133		)
Distributions to noncontrolling interest	—			—			—			—			—			(91,506		)	40,632			(50,874		)
Excess tax benefit from equity-based compensation	1,804			—			—			—			1,804			—			—			1,804
Purchase of units for restricted grants - HEP	—			—			—			—			—			(1,641		)	—			(1,641		)
Deferred financing costs and other	(8,665		)	(1,160		)	—			—			(9,825		)	(3,371		)	(359		)	(13,555		)
Net repayment of intercompany advances (1)	(342,576		)				—			342,576			—			—			—			—
Distributions to Parent (1)	—			(2,147,006		)	—			2,147,006			—			—			—			—
	(652,568		)	(2,148,166		)	(128,887		)	2,489,582			(440,039		)	182,684			40,273			(217,082		)
Cash and cash equivalents
Increase (decrease) for the period:	1,345,809			5,677			—			—			1,351,486			(1,683		)	—			1,349,803
Beginning of period	230,082			(9,035		)	2			—			221,049			8,052			—			229,101
End of period	$	1,575,891		$	(3,358	)	$	2		$	—		$	1,572,535		$	6,369		$	—		$	1,578,904

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


NOTE 22:	Significant Customers

All revenues are domestic revenues, except for refining segment sales of gasoline and diesel fuel for export into Mexico. We have two significant customers (Sinclair and Shell Oil), each of which has historically accounted for 10% or more of our annual revenues. Sinclair accounted for $2,134.3 million (11%), $2,106.6 million (10%) and $2,035.1 million (13%) of our revenues for the years ended December 31, 2013, 2012 and 2011, respectively, and Shell Oil accounted for $1,830.5 million (9%), $2,323.6 million (12%) and $1,540.6 million (10%) for the years ended December 31, 2013, 2012 and 2011, respectively. Our export sales were to an affiliate of PEMEX and accounted for $310.0 million (2%), $429.4 million (2%) and $370.0 million (2%) of our revenues for the years ended December 31, 2013, 2012 and 2011, respectively.


NOTE 23:	Quarterly Information (Unaudited)



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In thousands, except per share data)
Year Ended December 31, 2013
Sales and other revenues	$	4,707,789	$	5,298,848	$	5,327,122	$	4,826,801	$	20,160,560
Operating costs and expenses	$	4,158,594	$	4,838,842	$	5,177,372	$	4,739,678	$	18,914,486
Income from operations	$	549,195	$	460,006	$	149,750	$	87,123	$	1,246,074
Income before income taxes	$	529,465	$	417,792	$	137,437	$	74,705	$	1,159,399
Net income attributable to HollyFrontier stockholders	$	333,669	$	256,981	$	82,290	$	62,902	$	735,842
Net income per share attributable to HollyFrontier stockholders - basic	$	1.64	$	1.27	$	0.41	$	0.32	$	3.66
Net income per share attributable to HollyFrontier stockholders - diluted	$	1.63	$	1.27	$	0.41	$	0.31	$	3.64
Dividends per common share	$	0.80	$	0.80	$	0.80	$	0.80	$	3.20
Average number of shares of common stock outstanding:
Basic	202,726		201,543		199,098		198,371		200,419
Diluted	203,428		201,905		199,509		199,311		201,234

Year Ended December 31, 2012
Sales and other revenues	$	4,931,738	$	4,806,681	$	5,204,798	$	5,147,507	$	20,090,724
Operating costs and expenses	$	4,512,174	$	3,993,544	$	4,226,494	$	4,474,366	$	17,206,578
Income from operations	$	419,564	$	813,137	$	978,304	$	673,141	$	2,884,146
Income before income taxes	$	387,426	$	788,088	$	960,272	$	652,209	$	2,787,995
Net income attributable to HollyFrontier stockholders	$	241,696	$	493,499	$	600,373	$	391,604	$	1,727,172
Net income per share attributable to HollyFrontier stockholders - basic	$	1.16	$	2.40	$	2.95	$	1.92	$	8.41
Net income per share attributable to HollyFrontier stockholders - diluted	$	1.16	$	2.39	$	2.94	$	1.92	$	8.38
Dividends per common share	$	0.60	$	0.65	$	1.15	$	0.70	$	3.10
Average number of shares of common stock outstanding:
Basic	207,681		204,787		202,655		202,480		204,379
Diluted	208,288		205,541		203,532		203,498		205,274

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, 2013.

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 2013 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 14, 2014 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 14, 2014 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 14, 2014 and is incorporated herein by reference.

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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 14, 2014 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 14, 2014 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, 2013 and 2012	58

Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011	58

Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	59

Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	60

Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011	61

Notes to Consolidated Financial Statements	62

(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 105 to 112 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.

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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 25, 2014		/s/ Michael C. Jennings
		Michael C. Jennings
		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/ Michael C. Jennings	Chairman of the Board, Chief	February 25, 2014
Michael C. Jennings	Executive Officer and President

/s/ Douglas S. Aron	Executive Vice President and	February 25, 2014
Douglas S. Aron	Chief Financial Officer
	(Principal Financial Officer)

/s/ J.W. Gann, Jr.	Vice President, Controller and	February 25, 2014
J.W. Gann, Jr.	Chief Accounting Officer
	(Principal Accounting Officer)

/s/ Denise C. McWatters	Senior Vice President, General	February 25, 2014
Denise C. McWatters	Counsel and Secretary

/s/ Douglas Y. Bech	Director	February 25, 2014
Douglas Y. Bech

/s/ Buford P. Berry	Director	February 25, 2014
Buford P. Berry

/s/ Leldon Echols	Director	February 25, 2014
Leldon Echols

/s/ R. Kevin Hardage	Director	February 25, 2014
R. Kevin Hardage

/s/ Robert J. Kostelnik	Director	February 25, 2014
Robert J. Kostelnik

/s/ James H. Lee	Director	February 25, 2014
James H. Lee

/s/ Robert G. McKenzie	Director	February 25, 2014
Robert G. McKenzie

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Signature	Capacity	Date

/s/ Franklin Myers	Director	February 25, 2014
Franklin Myers

/s/ Michael E. Rose	Director	February 25, 2014
Michael E. Rose

/s/ Tommy A. Valenta	Director	February 25, 2014
Tommy A. Valenta

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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		Agreement and Plan of Merger among Holly Corporation, North Acquisition, Inc. and Frontier Oil Corporation, dated February 21, 2011 (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed February 22, 2011, 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 June 10, 2009, among Holly Corporation, the Guarantors and U.S. Bank Trust National Association, providing for the issuance of 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued thereunder) (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed June 11, 2009, File No. 1-03876).

4.2		First Supplemental Indenture, dated June 14, 2011, among Holly Corporation, the Guarantors and U.S. Bank Trust National Association (incorporated by reference to Exhibit 4.1 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-03876).

4.3		Second Supplemental Indenture, dated July 18, 2011, among HollyFrontier Corporation, the Guarantors and U.S. Bank Trust National Association (incorporated by reference to Exhibit 4.11 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876).

4.4		Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, providing for the issuance of 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 11, 2010, File No. 1-32225).

4.5		First Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., 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 June 30, 2010, File No. 1-32225).

4.6		Second Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, File No. 1-32225).

4.7		Third Supplemental Indenture, dated December 29, 2011, among Cheyenne Logistics LLC, El Dorado Logistics LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 of Holly Energy Partners, L.P.'s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-32225).

4.8		Fourth Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, File No. 1-03876).

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Exhibit Number		Description

4.9		Indenture, dated November 22, 2010, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association, providing for the issuance of 6 7/8% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K filed November 22, 2010, File Number 1-07627).

4.10		First Supplemental Indenture, dated November 22, 2010, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed November 22, 2010, File Number 1-07627).

4.11		Second Supplement Indenture, dated May 26, 2011, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed May 27, 2011, File No. 1-07627).

4.12		Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).

4.13		Form of 6 7/8% Senior Note Due 2018 (incorporated by reference to Exhibit 4.3 of Frontier Oil Corporation's Current Report on form 8-K filed November 22, 2010, file Number 1-07627).

4.14		Indenture, dated March 12, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, providing for the issuance of 6.50% Senior Notes due 2020 (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 12, 2012, File No. 1-32225).

4.15		First Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, 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).

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).

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Exhibit Number		Description

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		Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Refining & Marketing Company, Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.8 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225).

10.9		Letter Agreement, dated October 14, 2011, regarding the Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.14 of the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876).

10.10		Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013, 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, LLC and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).

10.11		Amended and Restated Refined Product Pipelines and Terminals Agreement, dated December 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Energy Partners - Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225).

10.12		Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing - Woods Cross and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.12 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.13		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 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013, File No. 1-03876).

10.14*		First Amendment to Amended and Restated Refined Product Pipelines and Terminals Agreement, dated November 7, 2013, effective September 30, 2013, among HollyFrontier Refining & Marketing LLC (formerly Holly Refining & Marketing LLC), Holly Energy Partners - Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C.

10.15		Pipeline Throughput Agreement (Roadrunner), dated December 1, 2009, between Navajo Refining Company, L.L.C. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.4 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225).

10.16		Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.14 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.17		Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing - Tulsa LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.17 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.18		Second Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement, dated August 31, 2011, between Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage - Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed September 1, 2011, File No. 1-03876).

10.19		Indemnification Proceeds and Payments Allocation Agreement, dated December 1, 2009, between HEP Tulsa LLC and Holly Refining & Marketing - Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed December 7, 2009, File No. 1-03876).

10.20		Pipeline Systems Operating Agreement, dated February 8, 2010, among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed February 9, 2010, File No. 1-32225).

106

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Exhibit Number		Description

10.21		First Amendment to Pipeline Systems Operating Agreement, dated March 31, 2010, among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876).

10.22		Loading Rack Throughput Agreement (Lovington), dated March 31, 2010, between Navajo Refining Company, L.L.C. and Holly Energy Storage-Lovington LLC (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876).

10.23		First Amended and Restated Lease and Access Agreement (East Tulsa), dated March 31, 2010, among Holly Refining & Marketing-Tulsa, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.4 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876).

10.24		LLC Interest Purchase Agreement, dated November 9, 2011, among HollyFrontier Corporation, Frontier Refining LLC, Frontier El Dorado Refining LLC, Holly Energy Partners-Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed November 10, 2011, File No. 1-03876).

10.25		First Amended and Restated Tankage, Loading Rack and Crude Oil Receiving Throughput Agreement (Cheyenne), dated November 11, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.26 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876).

10.26		First Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated November 11, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.27 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876).

10.27		Second Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed January 13, 2014, File No. 1-03876).

10.28		Seventh Amended and Restated Omnibus Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).

10.29		Eighth Amended and Restated Omnibus Agreement, dated July 16, 2013, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed July 22, 2013, File No. 1-03876).

10.30		Ninth Amended and Restated Omnibus Agreement, dated January 7, 2014, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed January 13, 2014, File No. 1-03876).

10.31		Lease and Access Agreement (Cheyenne), dated November 9, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed November 10, 2011, File No. 1-03876).

10.32*		First Amendment to Lease and Access Agreement (Cheyenne), effective June 5, 2012, between Frontier Refining LLC and Cheyenne Logistics LLC.

10.33		Lease and Access Agreement (El Dorado), dated November 9, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.6 of Registrant's Current Report on Form 8-K filed November 10, 2011, File No. 1-03876).

10.34*		First Amendment to Lease and Access Agreement ( El Dorado), effective August 15, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.

10.35*		Second Amendment to Lease and Access Agreement ( El Dorado), effective December 5, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.

10.36*		Third Amendment to Lease and Access Agreement ( El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.

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Exhibit Number		Description

10.37		Credit Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, Union Bank, N.A., as administrative agent and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).

10.38		First Amendment to Credit Agreement, dated August 24, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, Union Bank, N.A, as administrative agent and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed August 30, 2011, File No. 1-03876).

10.39		Second Amendment to Credit Agreement and First Amendment to Guarantee and Collateral Agreement, dated March 19, 2013, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, Union Bank, N.A., as administrative agent and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 21, 2013, File No. 1-03876).

10.40		Guarantee and Collateral Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries in favor of Union Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).

10.41		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).

10.42		Sixteenth Amendment dated November 1, 2009, to the 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) (incorporated by reference to Exhibit 10.14 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-07627).

10.43		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).

10.44		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).

10.45		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 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627).

10.46		LLC Interest Purchase Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P. and HEP UNEV Holdings LLC (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).

10.47		Limited Partial Waiver of Incentive Distribution Rights under the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated July 12, 2012 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).

10.48		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).

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Exhibit Number		Description

10.49		Transportation Services Agreement, dated July 16, 2013, between HollyFrontier Refining & Marketing LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 22, 2013, File No. 1-03876).

10.50		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).

10.51		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).

10.52		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).

10.53		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).

10.54+		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).

10.55+		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).

10.56+		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).

10.57+		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).

10.58+		Holly Corporation – Supplemental Payment Agreement for 2001 Service as Director (incorporated by reference to Exhibit 10.19 of Registrant's Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-03876).

10.59+		Holly Corporation – Supplemental Payment Agreement for 2002 Service as Director (incorporated by reference to Exhibit 10.20 of Registrant's Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-03876).

10.60+		Holly Corporation – Supplemental Payment Agreement for 2003 Service as Director (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-03876).

10.61+		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).

10.62+		Holly Corporation Employee Form of Change in Control Agreement (for grandfathered Holly Corporation employees) (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

10.63+		HollyFrontier Corporation Form of Change in Control Agreement (for legacy Frontier Oil Corporation executives) (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed February 24, 2012, File No. 1-03876).

10.64+		HollyFrontier Corporation Form of Amendment to Change in Control Agreement for Chief Executive Officer and Chief Financial Officer (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed May 10, 2012, File No. 1-03876).

10.65+		HollyFrontier Corporation Form of Change in Control Agreement (for legacy Holly Corporation employees) (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 30, 2012, File No. 1-03876).

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Exhibit Number		Description

10.66+		HollyFrontier Corporation Form of Change in Control Agreement (for HollyFrontier Corporation new hires and promotes) (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed March 30, 2012, File No. 1-03876).

10.67+		HollyFrontier Corporation Form of Amendment to Change in Control Agreement for David L. Lamp and George J. Damiris (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 14, 2013, File No. 1-03876).

10.68+		Form of Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.69+		Form of Executive Restricted Stock Agreement [time and performance based vesting] (incorporated by reference to Exhibit 10.7 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).

10.70+		Form of Employee Restricted Stock Agreement [time based vesting] (incorporated by reference to Exhibit 10.10 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).

10.71+		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).

10.72+		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).

10.73+		Form of Restricted Stock Agreement (time-based vesting) (incorporated by reference to Exhibit 4.13 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).

10.74+		Form of Notice of Grant of Restricted Stock (incorporated by reference to Exhibit 4.14 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).

10.75+		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).

10.76+		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).

10.77+		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).

10.78+		Retention and Assumption Agreement, dated February 21, 2011, among Frontier Oil Corporation, Holly Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Current Report on Form 8-K filed February 21, 2011, File No. 1-07627).

10.79+		Retention and Assumption Agreement, dated February 21, 2011, among Frontier Oil Corporation, Holly Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.2 to Frontier Oil Corporation's Current Report on Form 8-K filed February 21, 2011, File No. 1-07627).

10.80+		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).

10.81+		Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit Agreement with Double Trigger Vesting (incorporated by reference to Exhibit 10.15 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876).

10.82+		Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Restricted Stock Agreement with Double Trigger Vesting (incorporated by reference to Exhibit 10.16 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876).

10.83+		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).

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Exhibit Number		Description

10.84+		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).

10.85+		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).

21.1*		Subsidiaries of Registrant.

23.1*		Consent of Independent Registered Public Accounting Firm.

31.1*		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		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, 2013, 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.

111