Edgar Filing: HollyFrontier Corp

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2011

¨	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)

Registrant’s telephone number, including area code (214) 871-3555

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 x 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 x

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 x 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

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

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

On June 30, 2011 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $3.1 billion. (This is not to be 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.)

208,236,478 shares of Common Stock, par value $.01 per share, were outstanding on February 16, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 16, 2012, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2011, are incorporated by reference in Part III.

TABLE OF CONTENTS


Item		Page
	PART I
Forward-looking statements			3

Definitions			4

1 and 2.	Business and properties		6
1A.	Risk factors		23
1B.	Unresolved staff comments		35
3.	Legal proceedings		35
4.	Mine safety disclosures		38

	PART II

5.	Market for Registrant’s common equity, related stockholder matters and issuer purchases of equity securities		39
6.	Selected financial data		40
7.	Management’s discussion and analysis of financial condition and results of operations		41
7A.	Quantitative and qualitative disclosures about market risk		61

Reconciliations to amounts reported under generally accepted accounting principles			61

8.	Financial statements and supplementary data		64
9.	Changes in and disagreements with accountants on accounting and financial disclosure		106
9A.	Controls and procedures		106
9B.	Other information		106

	PART III

10.	Directors, executive officers and corporate governance		106
11.	Executive compensation		106
12.	Security ownership of certain beneficial owners and management and related stockholder matters		106
13.	Certain relationships and related transactions, and director independence		107
14.	Principal accounting fees and services		107

	PART IV

15.	Exhibits, financial statement schedules		108

Signatures			109

Index to exhibits			111

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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;

•

our ability to realize fully or at all the anticipated benefits of our “merger of equals” with Frontier; 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 that is used to manufacture tires and in the production of 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 clean alternative fuel produced from renewable biological resources.

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

“Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is a primary source of hydrogen for the refinery.

“Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules.

“Crude 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.

“Delayed coker unit” is a refinery unit that removes carbon from the bottom cuts of crude oil to produce unfinished light transportation fuels and petroleum coke.

“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.

“Hydrocracker” means a refinery unit that breaks down large complex hydrocarbon molecules into smaller more useful ones using a fixed bed of catalyst at high pressure and temperature with hydrogen.

“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.

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“Lubricant” or “lube” means a solvent neutral paraffinic product used in passenger and commercial vehicle engine oils, specialty products for metal working or heat transfer and other industrial applications.

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

“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.

“PPM” means parts-per-million.

“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.

“RFS2” or advanced renewable fuel standard is a regulatory mandate required by the Energy Independence and Security Act of 2007 that requires 36 billion gallons of renewable fuel to be blended into transportation fuels by 2022. New mandated blending requirements for this standard became effective July 1, 2010.

“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.

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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 (“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”) effective 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 light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We were incorporated in Delaware in 1947 and maintain our principal corporate offices at 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Our telephone number is 214-871-3555 and our internet website address is www.hollyfrontier.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A print copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the SEC website is available on our website on the Investors page. 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 for purposes of creating a more diversified company having a broader geographic sales footprint, stronger financial position and to create a more efficient corporate overhead structure, while also realizing synergies and promoting accretion to earnings per share. The legacy Frontier business operations consist of crude oil refining and the wholesale marketing of refined petroleum products. Frontier operated refineries in Cheyenne, Wyoming (the “Cheyenne Refinery”) and El Dorado, Kansas (the “El Dorado Refinery”) that serve markets in the Rocky Mountain and Plains States regions of the United States. The combined annual average crude oil capacity of these refineries is approximately 187,000 barrels per day. 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. 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 October 20, 2009, we sold a portion of the acquired crude oil petroleum storage tanks and certain refining-related crude oil receiving pipeline facilities to an affiliate of Plains All American Pipeline, L.P. (“Plains”) for $40 million.

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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.

On February 29, 2008, we sold certain assets to HEP consisting of crude oil pipelines, tankage and terminal facilities supporting our Navajo and Woods Cross Refineries. HEP is a variable interest entity (“VIE”) as defined under U.S. generally accepted accounting principles (“GAAP”). Under GAAP, HEP’s acquisition of these assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Therefore, we reconsolidated HEP effective March 1, 2008. Intercompany transactions with HEP are eliminated in our consolidated financial statements.

HEP made a number of acquisitions in 2009 through 2011. 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.”

As of December 31, 2011, we:

•

owned and operated the El Dorado Refinery located in El Dorado, Kansas, 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 75% interest in 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”);

•

owned Ethanol Management Company (“EMC”), a products terminal and blending facility near Denver, Colorado and a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a development stage biodiesel production facility located in Port Arthur, Texas; and

•

owned a 42% interest in HEP, 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 25% interest in SLC Pipeline LLC (“SLC Pipeline”), 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 effective March 1, 2008 (date of reconsolidation).

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 an aggregate crude capacity of 443,000 barrels per 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 2011, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 48%, 32%, 5% and 3%, respectively, of our total refinery sales volumes.

The following tables 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 margin 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.

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	Years Ended December 31,
	2011⁽¹⁰⁾		2010		2009⁽¹¹⁾
*Consolidated*
Crude charge (BPD) ⁽¹⁾		315,000		221,440		142,430
Refinery throughput (BPD) ⁽²⁾		340,200		234,910		154,940
Refinery production (BPD) ⁽³⁾		331,890		225,980		151,420
Sales of produced refined products (BPD)		332,720		228,140		151,580
Sales of refined products (BPD) ⁽⁴⁾		340,630		232,100		155,820

Refinery utilization ⁽⁵⁾		89.9%		86.5%		78.9%

Average per produced barrel ⁽⁶⁾
Net sales	$	118.82	$	91.06	$	74.06
Cost of products ⁽⁷⁾		98.18		82.27		66.85

Refinery gross margin		20.64		8.79		7.21
Refinery operating expenses ⁽⁸⁾		5.36		5.08		5.24

Net operating margin	$	15.28	$	3.71	$	1.97


Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.24	$	4.94	$	5.12

Feedstocks:
Sour crude oil		23%		35%		49%
Sweet crude oil		56%		53%		40%
Black wax crude oil		2%		3%		5%
Heavy sour crude oil		12%		4%		— %
Other feedstocks and blends		7%		5%		6%

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). Our consolidated crude capacity was increased by 15,000 BPSD effective April 1, 2009 (our Navajo Refinery expansion), 85,000 BPSD effective June 1, 2009 (our Tulsa West facility acquisition) and 40,000 BPSD effective December 1, 2009 (our Tulsa East facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD. As a result of our merger effective July 1, 2011 our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD.

(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.

(9)

Represents refinery operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.

(10)

We merged with Frontier effective July 1, 2011. 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, averaged over the 365 days in the year ended December 31, 2011.

(11)

The amounts reported for the Mid-Continent refineries for the year ended December 31, 2009 include crude oil processed and products yielded from the Tulsa Refineries for the period from June 1, 2009 through December 31, 2009 only, averaged over the 365 days for the year ended.

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Principal Products and Customers

Set forth below is information regarding our principal products.


	Years Ended December 31,
	2011			2010			2009
*Consolidated*
Sales of produced refined products:
Gasolines		48	%		49	%		51	%
Diesel fuels		32	%		31	%		31	%
Jet fuels		5	%		5	%		4	%
Asphalt		4	%		3	%		2	%
Lubricants		3	%		5	%		4	%
Fuel oil, gas oil/intermediates, LPG and other		8	%		7	%		8	%

Total		100	%		100	%		100	%

Light products are shipped by product pipelines or are made available at various points by exchanges with other parties and are made available to customers through truck loading facilities at the refinery and at terminals.

We have several significant customers, of which two accounted for more than 10% of our business in 2011. For the year ended December 31, 2011, Sinclair accounted for $2,035.1 million, or 13%, of our revenues and Shell Oil accounted for $1,540.6 million, or 10%, 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 military and 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.

Mid-Continent Region (Tulsa and El Dorado Refineries)

Facilities

On June 1, 2009, we acquired the Tulsa West facility, an 85,000 BPSD refinery in Tulsa, Oklahoma from Sunoco. On December 1, 2009, we acquired the Tulsa East facility, a 75,000 BSPD refinery that is also located in Tulsa, Oklahoma from Sinclair. We have integrated certain refining processes between our Tulsa West and East facilities. In September 2011, HEP completed the Tulsa interconnecting pipeline project which facilitated a combined crude processing rate of 125,000 BPSD. On July 1, 2011, the merger with Frontier added the El Dorado Refinery with a 135,000 BSPD capacity. The El Dorado Refinery is a high-complexity coking refinery with the ability to process significant volumes of heavy and sour crudes. For 2011, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 44%, 32%, 7% and 6%, 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,
	2011⁽¹⁰⁾		2010		2009 ⁽¹¹⁾
*Mid-Continent Region (Tulsa and El Dorado Refineries)*
Crude charge (BPD)⁽¹⁾		183,070		111,670		39,370
Refinery throughput (BPD) ⁽²⁾		194,310		113,100		39,520
Refinery production (BPD) ⁽³⁾		188,760		106,910		38,910
Sales of produced refined products (BPD)		188,020		107,780		37,570
Sales of refined products (BPD) ⁽⁴⁾		190,340		108,330		37,700

Refinery utilization ⁽⁵⁾		94.8%		89.3%		74.0%

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		$00000000		$00000000		$00000000
	Years Ended December 31,
	2011⁽¹⁰⁾		2010		2009 ⁽¹¹⁾
Average per produced barrel ⁽⁶⁾
Net sales	$	119.51	$	90.84	$	78.89
Cost of products ⁽⁷⁾		99.92		83.29		74.56

Refinery gross margin		19.59		7.55		4.33
Refinery operating expenses ⁽⁸⁾		5.04		4.94		5.25

Net operating margin	$	14.55	$	2.61	$	(0.92	)


Refinery operating expenses per throughput barrel ⁽⁹⁾	$	4.88	$	4.71	$	4.99

Feedstocks:
Heavy sour crude oil		8%		3%		— %
Sweet crude oil		82%		92%		100%
Sour crude oil		4%		5%		— %
Other feedstocks and blends		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 process 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 3.7 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.

The Tulsa West facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa West facility consist of crude 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, and an additional 1.2 million barrels of tank capacity is currently out of service but could be made available for future use.

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 distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. The Tulsa East facility’s Supporting Infrastructure includes approximately 3.75 million barrels of tankage capacity on the refinery’s premises, of which approximately 3.4 million barrels of tankage is owned by HEP.

In 2011, we integrated certain Tulsa refining operations and through this process now have a highly complex refining operation with a combined crude processing rate of approximately 125,000 BPSD.

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.

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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 period July 1, 2011 to December 31, 2011, sales to Shell represented approximately 50% of the El Dorado Refinery’s total sales and 10% of our total consolidated sales. We have an offtake agreement with Shell Oil Products US (“Shell”) under which Shell purchases gasoline and diesel production of the El Dorado Refinery at market-based prices through December 2014. Shell also has agreed to purchase all jet fuel production until the end of the product offtake agreement. In aggregate during 2011, we retained and marketed 60,000 bpd of the refinery’s gasoline and diesel production while the remaining production was sold to Shell. We market gasoline and diesel in the same markets where Shell sells the refinery’s products, primarily in Denver and throughout the Plains States. Upon expiration of the offtake agreement, we intend to sell the gasoline and diesel produced by the El Dorado Refinery in the same general markets served by Shell.

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 two 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, we entered a five-year offtake agreement through 2014 with an affiliate of Sinclair whereby Sinclair agreed to purchase 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, 2011, sales to Sinclair represented approximately 40% of the Tulsa Refineries total sales and 13% 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 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 the United States 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 oils, primarily formulated as supplemental carriers for herbicides, 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 9% 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,
	2011		2010		2009
*Mid-Continent Region (El Dorado and Tulsa Refineries)*
Sales of produced refined products:
Gasolines		44%		38%		26%
Diesel fuels		32%		31%		29%
Jet fuels		7%		8%		10%
Lubricants		6%		11%		16%
Gas oil / intermediates		3%		4%		17%
Asphalt		4%		5%		— %
LPG and other		4%		3%		2%

Total		100%		100%		100%

Crude Oil and Feedstock Supplies

The El Dorado Refinery is located about 125 miles, and the Tulsa Refineries are located approximately 50 miles from Cushing, Oklahoma, a significant crude oil pipeline trading and storage hub. 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.

Both our Mid-Continent Refineries are connected via pipeline to Cushing, Oklahoma. In addition, we have a transportation services agreement to transport up to 38,000 bpd of crude oil on the Spearhead Pipeline from Flanagan, Illinois to Cushing, Oklahoma, enabling us to transport Canadian crude oil to Cushing for subsequent shipment to either of our Mid-Continent Refineries or to our Navajo Refinery. The initial term of this agreement expires in 2016. We have the right to extend the agreement for an additional ten years and to increase the volume transported under a preferential tariff to 50,000 bpd.

Southwest Region (Navajo Refinery)

Facilities

The Navajo Refinery has a crude oil capacity of 100,000 BPSD and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. For 2011, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 52%, 34% and 1%, respectively, of our Southwest sales volumes.

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

		$000000000			$000000000			$000000000
	Years Ended December 31,
	2011⁽¹⁰⁾			2010			2009
*Southwest Region (Navajo Refinery)*
Crude charge (BPD) ⁽¹⁾		83,700			83,900			78,160
Refinery throughput (BPD) ⁽²⁾		93,260			94,270			88,900
Refinery production (BPD) ⁽³⁾		91,810			92,050			86,760
Sales of produced refined products (BPD)		93,950			92,550			87,140
Sales of refined products (BPD) ⁽⁴⁾		98,540			95,790			90,870

Refinery utilization ⁽⁵⁾		83.7	%		83.9	%		81.2	%

Average per produced barrel ⁽⁶⁾
Net sales	$	118.76		$	90.37		$	73.15
Cost of products ⁽⁷⁾		98.40			83.12			65.95

Refinery gross margin		20.36			7.25			7.20
Refinery operating expenses ⁽⁸⁾		5.44			4.95			4.81

Net operating margin	$	14.92		$	2.30		$	2.39

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		$000000000		$000000000		$000000000
	Years Ended December 31,
	2011⁽¹⁰⁾		2010		2009
Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.48	$	4.86	$	4.71

Feedstocks:
Sour crude oil		75%		81%		85%
Sweet crude oil		3%		5%		6%
Heavy sour crude oil		11%		4%		— %
Other feedstocks and blends		11%		10%		9%

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 million barrels of feedstock and product tankage, of which 0.2 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 Plains 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, the Navajo Refinery transports petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via HEP’s pipelines running from Artesia to San Juan County, 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, Moriarty and Bloomfield, 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 ConocoPhillips and EnCana Corp.), Valero, Alon (“Alon”), and Western Refining. Pipelines serving this market are owned by Magellan Midstream Partners, L.P. (“Magellan”), NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines, including Magellan’s Longhorn Pipeline acquired in 2009.

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 Longhorn Pipeline delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market.

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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.

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 Bloomfield, New Mexico, which is located in the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of Albuquerque. These facilities permit us to ship light products to the Albuquerque and Santa Fe, New Mexico areas, which have historically experienced high growth rates. If needed, additional pump stations could further increase the pipeline’s capabilities.

Principal Products

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

		December 31			December 31			December 31
	Years Ended December 31,
	2011			2010			2009
*Southwest Region (Navajo Refinery)*
Sales of produced refined products:
Gasolines		52	%		57	%		58	%
Diesel fuels		34	%		32	%		32	%
Jet fuels		1	%		3	%		2	%
Fuel oil		6	%		4	%		3	%
Asphalt		4	%		2	%		3	%
LPG and other		3	%		2	%		2	%

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 Spearhead Pipeline 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 oil companies for use as feedstock.

Rocky Mountain Region (Cheyenne and Woods Cross Refineries)

Facilities

The Cheyenne Refinery has a crude oil capacity of 52,000 BPSD and the Woods Cross Refinery has a crude oil capacity of 31,000 BPSD. 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 2011, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 56%, 31% and 1%, respectively, of our Rocky Mountain sales volumes.

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


	Years Ended December 31,
	2011⁽¹⁰⁾			2010			2009
*Rocky Mountain Region (Cheyenne and Woods Cross Refineries)*
Crude charge (BPD)⁽¹⁾		48,230			25,870			24,900
Refinery throughput (BPD) ⁽²⁾		52,630			27,540			26,520
Refinery production (BPD) ⁽³⁾		51,320			27,020			25,750
Sales of produced refined products (BPD)		50,750			27,810			26,870
Sales of refined products (BPD) ⁽⁴⁾		51,750			27,980			27,250

Refinery utilization ⁽⁵⁾		84.3	%		83.5	%		80.3	%

Average per produced barrel ⁽⁶⁾
Net sales	$	116.37		$	94.26		$	70.25
Cost of products ⁽⁷⁾		91.33			75.54			58.98

Refinery gross margin		25.04			18.72			11.27
Refinery operating expenses ⁽⁸⁾		6.41			6.09			6.60

Net operating margin	$	18.63		$	12.63		$	4.67


Refinery operating expenses per throughput barrel ⁽⁹⁾	$	6.18		$	6.15		$	6.69

Feedstocks:
Heavy sour crude oil		24	%		6	%		5	%
Sweet crude oil		52	%		59	%		62	%
Sour crude oil		1	%		—	%		—	%
Black wax crude oil		15	%		30	%		28	%
Other feedstocks and blends		8	%		5	%		5	%

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 1.6 million barrels of feedstock and product tankage, of which 1.5 million barrels of tankage are 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 at 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 plan to expand the Woods Cross refinery capacity to 45,000 BPSD at a cost of approximately $225 million. The expansion is expected to be completed in late 2014. The expansion scope includes the relocation / revamp of crude, fluid catalytic cracking, and polymerization units from a subsidiary of Western Refining Inc.’s (“Western”) Bloomfield, New Mexico refinery to Woods Cross as well an expansion of the Woods Cross diesel hydrotreater. We have signed a definitive agreement with Western for the purchase of the Bloomfield units.

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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 region to the Woods Cross Refinery, which currently has capacity to process approximately 10,000 bpd of these crudes. Upon completion of this expansion, the Woods Cross Refinery will be able to process approximately 24,000 bpd of waxy Utah crudes. This expansion and crude oil supply agreement, and expected completion timeline, are subject to HollyFrontier successfully obtaining the necessary permits and regulatory approvals.

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 Plains pipeline serving Denver and Colorado Springs, Colorado and HEP’s pipeline to Sidney Nebraska.

Denver Market

The most competitive market for the Cheyenne Refinery is the Denver metropolitan area. Three other refineries supply the Denver market, a refinery near Rawlins and one in Casper, both in Wyoming and owned by Sinclair and a refinery in Denver owned by Suncor. Five product pipelines also supply Denver, including three from outside the region. Typically products shipped in from other regions bear higher transportation costs. The Suncor refinery has lower product transportation costs than we do; however, we have lower crude oil transportation costs because the Cheyenne Refinery is located 88 miles south of Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky Mountain region. Moreover, unlike Sinclair and Suncor, we only sell our products to the wholesale market. We believe this gives us an advantage because all of the Cheyenne Refinery’s principal competitors have retail outlets and we do not directly compete with independent retailers of gasoline and diesel.

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. Local area refiners include Woods Cross, Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and ConocoPhillips. We estimate that the four 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 ConocoPhillips. 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 Chevron’s common carrier pipeline system to numerous terminals, including HEP’s terminals at Boise and Burley, Idaho and Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Northwest Terminalling Pipeline Company. We sell to branded and unbranded customers in these markets.

We have historically trucked refined products to Las Vegas, Nevada. 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. See our discussion of the UNEV Pipeline below that will permit our Woods Cross Refinery to ship significant volumes of refined product to Cedar City, Utah and Las Vegas, Nevada beginning in 2012.

Principal Products

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

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		December 31			December 31			December 31
	Years Ended December 31,
	2011			2010			2009
*Rocky Mountain Region (Cheyenne and Woods Cross Refineries)*
Sales of produced refined products:
Gasolines		56	%		63	%		64	%
Diesel fuels		31	%		30	%		28	%
Jet fuels		1	%		1	%		1	%
Fuel oil		1	%		1	%		3	%
Asphalt		6	%		3	%		2	%
LPG and other		5	%		2	%		2	%

Total		100	%		100	%		100	%

Crude Oil and Feedstock Supplies

Crude oil is transported to the Cheyenne Refinery from suppliers in Canada, 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 its supply of crude oil from suppliers in Canada, Wyoming, Utah and Colorado as delivered via common carrier pipelines that originate in Canada, Wyoming and Colorado. In 2009, we also began receiving 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.

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 Ethanol Management Company, a 25,000 bpd products terminal and blending facility located near Denver, Colorado. We also 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.

UNEV Pipeline

We own a 75% joint venture interest in the recently completed UNEV Pipeline, a 400 mile 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal and ethanol blending facilities in the Cedar City, Utah and North Las Vegas areas and storage facilities at the Cedar City terminal with Sinclair, our joint venture partner, owning the remaining 25% interest. The pipeline has a capacity of 62,000 BPD (based on gasoline equivalents), and has the capacity for further expansion to 120,000 BPD. The cost of constructing this pipeline including terminals and ethanol blending and storage facilities was approximately $410 million. The pipeline was mechanically complete in November 2011, and initial start-up activities commenced in December 2011.

We have entered into a 10-year minimum annual revenue guaranty of $15.4 million per year per year on the UNEV Pipeline. This entitles us to ship approximately 15,500 BPD of refined product at a lower incentive tariff rate. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

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HOLLY ENERGY PARTNERS, L.P.

In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that also 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 owns and operates a system of petroleum product and crude oil pipelines in New Mexico, Oklahoma, Texas and Utah and 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, by leasing certain pipeline capacity to Alon by charging fees for terminalling refined products and other hydrocarbons and 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 2011) are summarized below:

2011 Acquisition

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 million and 3.8 million HEP common units.

2010 Acquisition

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, HEP acquired from us certain storage assets for $93 million, consisting of hydrocarbon storage tanks having approximately 2 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.

2009 Acquisitions

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. The racks load refined products and lube oils produced at the Tulsa West facility onto rail cars and/or tanker trucks.

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.

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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 million. Results of operations of Rio Grande are presented in discontinued operations.

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. 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, 2011, these agreements result in minimum annualized payments to HEP of $192 million.

We reconsolidated HEP effective March 1, 2008. Following our reconsolidation, our transactions with HEP including fees that we pay under our HEP transportation agreements are eliminated and have no impact on our consolidated financial statements since HEP is a consolidated VIE.

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, 2011, HEP’s assets include:

Pipelines

•

approximately 820 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 960 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;

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gasoline and diesel connecting pipelines that support our Tulsa East facility;

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five intermediate product and gas pipelines between the Tulsa East and Tulsa West facilities; and

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crude receiving assets located at our Cheyenne Refinery.

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Refined Product Terminals and Refinery Tankage

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four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,000,000 barrels, that are integrated with HEP’s refined product pipeline system that serves our Navajo Refinery;

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three refined product terminals (two of which are 50% owned) located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000 barrels, that serve 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;

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two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with HEP’s refined product pipelines that serve Alon’s Big Spring, Texas refinery;

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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;

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a leased jet fuel terminal in Roswell, New Mexico;

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on-site crude oil tankage at our Tulsa, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity of approximately 1,400,000 barrels;

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on-site crude oil, refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate storage capacity of approximately 8,300,000 barrels;

HEP also owns a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City area.

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

We lease approximately 46,000 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, 2011, we had 2,382 employees, of which 797 are currently covered by collective bargaining agreements having various expiration dates between 2012 and 2016. 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. 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.

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Under the CAA, the Environmental Protection Agency (“EPA”) has the authority to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. In June 2004, the EPA issued new regulations limiting emissions from diesel fuel powered engines used in non-road activities such as mining, construction, agriculture, rail transport, and marine operations and simultaneously limiting the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. As of December 31, 2011, all of our refineries produce non-road and highway diesel that meets the ultimate 15 ppm sulfur standard.

Our refineries are subject to another EPA regulation limiting the annual average sulfur content in gasoline to 30 ppm. Currently, our refineries either meet this standard and balance annual average requirements by purchasing from third parties or using internally generated sulfur credits.

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 Tulsa, Navajo and Woods Cross Refineries currently purchase benzene credits to meet these requirements. Our remaining refineries become subject to the regulation in 2013. Our planned capital projects will reduce the amount of benzene credits that we need to purchase. If economically justified, we could implement additional benzene reduction projects to eliminate the need to purchase any benzene credits.

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. 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, and litigation challenging the EPA’s authority over greenhouse gas emissions is currently pending in federal court.

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 permits, 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

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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, 2011, we had an accrual of $42.2 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.

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.

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 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.

Insurance

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

We have a risk management oversight committee that is made up of members from our senior management. This committee 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 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. 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. 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 flows. 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 results.

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, 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

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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 such as our UNEV Pipeline joint venture, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada in which our subsidiary owns a 75% interest. 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;

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compliance with or liability under environmental regulations;

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unplanned increases in the cost of construction materials or labor;

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disruptions in transportation of modular components and/or construction materials;

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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;

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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

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market-related increases in a project’s debt or equity financing costs; and/or

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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 results of operations and financial condition.

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.

In addition, a 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:

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diversion of management time and attention from our existing business;

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challenges in managing the increased scope, geographic diversity and complexity of operations;

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difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;

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liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;

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greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;

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difficulties in achieving anticipated operational improvements;

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incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and

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issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

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

As of December 31, 2011, the principal amount of our total consolidated outstanding debt was $1,214.4 million, including $535 million of HEP debt.

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

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 most recently, low consumer confidence, continued 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 existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or announced and future pipeline construction projects, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

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, 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.

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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 soil and water 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.

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 our operations and demand for our products.

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.

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

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reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing or requiring state environmental agencies to implement the rules. 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.

In addition, the United States 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.

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. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, 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.

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 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

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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; the yield and product quality of new equipment may differ from design and/or specifications and redesign or modification 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 results of operations and financial condition.

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

Our 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 or destruction of property, injury, or extensive property damage, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. Furthermore, we may not be able 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. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. 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.

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. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. 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.

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.

Insufficient ethanol, biodiesel, and other advanced biofuel supplies, or disruption in supply, may disrupt our ability to meet RFS2 regulations mandated by the federal government or required in the fuels markets that we serve.

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If we are unable to obtain or maintain sufficient quantities of ethanol for our blending needs, our sale of ethanol gasoline (required in several of our markets) could be interrupted or suspended which could result in lower profits. Likewise, if we are unable to purchase renewable identification numbers (“RINs”), or if our supply of RINs is such that we have to pay a significantly higher price for RINs to meet our mandated blending volumes of biofuels per the RFS2 regulation, our profits would be significantly lower. If we are unable to pass the costs of compliance with RFS2 on to our customers, our profits would be significantly lower.

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.

Portions of our operations in the areas we operate 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.

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.

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

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. For example, we face certain challenges as we continue to integrate the operations of Frontier Oil Corporation, with whom we merged in 2011, into our business. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of the acquisitions we recently completed or as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, including the merger in 2011. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.

The new and revamped equipment in our facilities may not perform according to expectations which may cause unexpected maintenance and downtime and could have a negative effect on our future results of operations and financial condition.

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From time to time, we have major capital investment and various environmental compliance related projects at our refineries. The installation of new equipment and the revamp of key existing equipment involve significant risks and uncertainties, including the following:

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Equipment may not perform at expected throughput levels;

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Actual yields or product quality may differ from design;

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Actual operating costs may be higher than expected;

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Equipment may need to be redesigned, revamped, or replaced for the new units to perform as expected.

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.

The disruption 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 Cheyenne, El Dorado, Navajo, Woods Cross, and Tulsa 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.

The proposed reversal of the Seaway Pipeline is expected to increase demand for crude oil from the Northwestern United States and Canada, which we expect to affect price advantages that have been in our favor and which may adversely affect our profit margins.

On November 16, 2011, Enbridge Inc. and Enterprise Products Partners L.P. announced that they had agreed with ConocoPhillips to acquire the Seaway Crude Pipeline System. The 670-mile Seaway Crude Pipeline System includes the 500-mile, 30-inch diameter Freeport, Texas to Cushing, Oklahoma long-haul system. This pipeline currently transports crude oil to the Cushing facility from the U.S. Gulf Coast; however, Enbridge, Inc. and Enterprise Products Partners L.P. announced their intention to reverse the direction of crude oil flows on the Seaway pipeline such that it will transport crude from Cushing, Oklahoma to the U.S. Gulf Coast.

Our profit margins depend primarily on the spread between the price of crude oil and the price of the refined product. We were generally able to purchase crude oil at a favorable price due to a bottleneck of crude oil at the Cushing, Oklahoma transport hub. This bottleneck prevented crude from the Northwestern United States and Canada from reaching many competing refineries. The reversal of the Seaway Crude Pipeline is expected to alleviate this bottleneck, and therefore could eliminate the market dynamic that allowed us to enjoy favorable pricing. This may adversely affect our profit margins.

The potential operation of new or expanded refined product transportation pipelines could impact the supply of refined products to our existing markets.

The refined product transportation pipelines that also supply the markets supplied by the Navajo Refinery include Longhorn, Kinder Morgan, Plains, HEP, and NuStar Energy. The Longhorn Pipeline is a common carrier pipeline that supplies the El Paso market with refined products from refineries as distant as the Texas Gulf Coast. The Longhorn Pipeline is a converted crude oil pipeline with an approximate capacity of 72,000 BPD of refined products. Magellan purchased the Longhorn Pipeline out of bankruptcy in 2009. Flying J formerly owned the Longhorn Pipeline prior to its bankruptcy in 2008. In addition to supplying Arizona markets from El Paso, Kinder Morgan also supplies Arizona markets from the West Coast. The Plains pipeline currently supplies New Mexico markets from El Paso. In addition, NuStar Energy LP and HEP own pipelines into the El Paso and New Mexico markets.

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The refined product transportation pipelines that also supply the markets supplied by the Woods Cross Refinery include Chevron, Pioneer, and Yellowstone Pipelines. The Chevron system transports products from Salt Lake City to Idaho and eastern Washington. The Pioneer Pipeline transports products from Wyoming and Montana refineries into Salt Lake City. The Yellowstone Pipeline transports products from Montana refineries into eastern Washington.

The refined product transportation pipelines that also supply the markets supplied by the Tulsa and El Dorado Refineries include Magellan, Explorer, and Kaneb Pipelines. The Explorer Pipeline transports refined products from Gulf Coast refineries to Tulsa where it interconnects with Magellan prior to proceeding to the Chicago area. The Kaneb Pipeline transports refined products from northern Texas, Oklahoma, and Kansas refineries to markets in Kansas, Nebraska, Iowa, North Dakota, and South Dakota. These markets are in close proximity to markets supplied by the Magellan system.

The refined product transportation pipelines that also supply the markets supplied by the Cheyenne Refinery include Rocky Mountain, Magellan Mountain, Conoco, Medicine Bow, and Nustar Pipelines. The Rocky Mountain Pipeline System which transports the Cheyenne Refinery’s products to Denver also transports refined products from Wyoming and further north to Cheyenne and Denver. The Medicine Bow pipeline delivers refined products from Sinclair Wyoming. The Magellan Mountain pipeline delivers refined products directly from Kansas but those products may be supplied all the way from the Gulf Coast. The Conoco and Nustar pipelines bring products in from the Texas Panhandle.

The expansion of any of these pipelines, the conversion of existing pipelines into refined products, or the construction of a new pipeline into our markets could negatively impact the supply of refined products in our markets and our profitability.

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 42% 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, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves our refineries in New Mexico, Utah, Wyoming, Kansas and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2025. 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:

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its reliance on its significant customers, including us;

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competition from other pipelines;

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environmental regulations affecting pipeline operations;

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operational hazards and risks;

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pipeline tariff regulations affecting the rates HEP can charge;

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limitations on additional borrowings and other restrictions due to HEP’s debt covenants; and

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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.”

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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 hostilities in the Middle East 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 hostilities in the Middle East 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.

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

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors outside our control, including competition from other refiners and the demand for refined products in the markets that we serve. Loss of, or reduction in, amounts purchased by our major customers could have an adverse effect on us to the extent that, because of market limitations or transportation constraints, we are not able to correspondingly increase sales to other purchasers.

Our petroleum business’ financial results are seasonal and generally lower in the first and fourth quarters of the year, which may cause volatility in the price of our common stock.

Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel fuel, which in the Southwest region of the United States is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes. However, 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 could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and reduce operating margins.

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We may be unable to pay future dividends.

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

Ongoing maintenance of effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.

We regularly document and test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our internal controls and, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could cause us to incur substantial expenditures of management time and financial resources to identify and correct any such failure.

Additionally, the failure to comply with Section 404 or the report by us of a “material weakness” may cause investors to lose confidence in our financial statements and our stock price may be adversely affected. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may decline.

Product liability claims and litigation could adversely affect our business and results of operations.

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. Failure of our products to meet required specifications could result in product liability claims from our shippers and customers arising from contaminated or off-specification commingled pipelines and storage tanks and/or defective quality fuels.

If the market value of our inventory declines to an amount less than our LIFO basis, we would record a write-down of inventory and a non-cash charge to cost of sales, which would adversely affect our earnings.

The nature of our business requires us to maintain substantial quantities of crude oil, refined petroleum product and blendstock inventories. Because crude oil and refined petroleum products are commodities, we have no control over the changing market value of these inventories. Because certain of our refining inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology, we would record a write-down of inventory and a non-cash charge to cost of sales if the market value of our inventory were to decline to an amount less than our LIFO basis. A material write-down could affect our operating income and profitability.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are not able to obtain the necessary funds from financing activities.

We have significant short-term cash needs to satisfy working capital requirements such as crude oil purchases which fluctuate with the pricing and sourcing of crude oil.

We generally purchase crude oil for our refineries with cash generated from our operations. If the price of crude oil increases significantly, we may not have sufficient cash flow, available cash on hand or borrowing capacity, and may not be able to sufficiently increase borrowing capacity, under our existing credit facilities to purchase enough crude oil to operate our refineries at desired capacity. Our failure to operate our refineries at desired capacity could

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have a material adverse effect on our business, financial condition and results of operations. We also have significant long-term needs for cash, including those to support our expansion and upgrade plans, as well as for regulatory compliance. If credit markets tighten, it may become more difficult to obtain cash from third party sources. If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with regulatory deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect, and we could be subject to regulatory action.

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 enough 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 facilities 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) maintenance of certain levels of the fixed charge coverage ratio; (ii) limitations on liens, investments, indebtedness and dividends; (iii) a prohibition on changes in control and (iv) 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. Should we desire to undertake a transaction that is prohibited by the covenants in our credit facilities, we will need to obtain consent under our credit facilities. Such refinancing may not be possible or may not be available on commercially acceptable terms. In addition, our obligations under our credit facilities are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facilities 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.

Our business may suffer due to a change in the composition of our Board of Directors, or if any of our key senior executives or other key employees discontinue employment with us. 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.

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As of December 31, 2011, 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.

We may need to use current cash flow to fund our postretirement health care obligations, which could have a significant adverse effect on our financial position.

We also have benefit obligations in connection with our unfunded postretirement health care plans that provide health care benefits as part of the voluntary early retirement program offered to eligible employees. As part of the early retirement program, we allow qualified retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. As of December 31, 2011, the total accumulated postretirement benefit obligation under our postretirement medical plans was $77.3 million. Increased participation in this program and/or increasing medical costs may affect our ability to pay required health care benefits causing us to have to divert funds away from other areas of the business to pay their costs.

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.

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, off specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages caused by the off specification fuel or could impact our ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.

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.

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.

Cut Bank Hill Environmental Claims

Prior to the sale by Holly Corporation of the Montana Refining Company (“MRC”) assets in 2006, MRC (along with other companies) was the subject of several environmental claims at the Cut Bank Hill site in Montana. These claims include: (1) a U.S. Environmental Protection Agency (“EPA”) administrative order requiring MRC and other

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companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against MRC and other companies for response costs of $0.3 million in connection with its cleanup efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of Environmental Quality (“MDEQ”) directing MRC and other companies to complete a remedial investigation and a request by the MDEQ that MRC and other companies pay $0.2 million to reimburse the State’s costs for remedial actions. MRC has denied responsibility for the requested EPA order and the MDEQ cleanup actions and the MDEQ and Coast Guard response costs, but has accepted an invitation by the other companies to participate in the group based on an allocation of approximately 10 percent of the group’s past and ongoing investigation and other costs. This matter is no longer considered to be material based upon information currently available to the Company and will not be disclosed in future SEC filings.

Navajo Tank Fire

On March 2, 2010, a tank caught fire while under construction. At the time of the incident, four individuals were working on top of the tank. These individuals were all employees of a third-party contractor who was placing insulation on the tank. Two individuals sustained injuries and two individuals died as a result of the incident. Two wrongful death lawsuits and two personal injury lawsuits seeking damages, including punitive damages, were filed on behalf of the estates of the two deceased workers and on behalf of the two survivors in state court in Dallas County, Texas (two lawsuits) and state court in Eddy County, New Mexico (two lawsuits). A confidential settlement was reached in the two Texas cases, and the cases have been dismissed. Agreements have been reached for the settlement of the New Mexico cases, and those agreements are being documented. It is anticipated that the New Mexico cases will be dismissed shortly. These cases will no longer be reported in our SEC filings since they are not expected to be material due to our insurance coverage.

New Mexico OHSB Complaint – Navajo Tank Fire

On March 3, 2010, the New Mexico Occupational Health and Safety Bureau (“OHSB”), the New Mexico regulatory agency responsible for enforcing certain state occupational health and safety regulations, which are identical to Federal Occupational Safety and Health Administration (“OSHA”) regulations, commenced an inspection in relation to the tank fire that took place on March 2, 2010 at the Navajo facility in Artesia, New Mexico. On August 31, 2010, OHSB issued two citations to Navajo, alleging 10 willful violations and one serious violation of various construction safety standards. OHSB proposed penalties in the amount of $0.7 million. Navajo filed a notice of contest, challenging the citations. The parties commenced settlement negotiations but were unable to reach an agreement, thus OHSB filed an administrative complaint with New Mexico Occupational Health and Safety Review Commission (“OHSRC”) on December 20, 2010. Discovery is under way at this time. Due to the complexity of the case and a recent substitution of counsel for New Mexico, OHSRC recently extended the schedule in this matter, setting the hearing to begin no sooner than January 2013.

Discharge Permit Appeal – Tulsa West Facility

HRM-Tulsa is party to parallel Oklahoma administrative and state district court proceedings involving a challenge to the terms of the Oklahoma Department of Environmental Quality (“ODEQ”) permit that governs the discharge of industrial wastewater from our Tulsa West facility. Pursuant to a settlement agreement between HRM -Tulsa and ODEQ, both proceedings have been stayed to allow ODEQ to issue a revised permit that modifies the existing permit’s requirements for toxicity testing and for managing storm flows. The parties are now in discussions regarding the appropriate changes in the permit language to accomplish these modifications. Once agreed-upon revisions are made and become effective, both proceedings will be dismissed. This matter is no longer considered to be material based upon information currently available to the Company and will not be disclosed in future SEC filings.

Benzene Waste Operations Regulatory Proceedings – Tulsa East and West Facilities

On July 13, 2011, the EPA issued a determination that HRM—Tulsa’s two refineries should be considered a single facility for purposes of a particular Clean Air Act regulation, the Benzene Waste Operations NESHAP. As a single facility, the refineries’ emissions would be combined for purposes of assessing whether they were exceeding the relevant regulatory threshold. We disagreed with this interpretation, however, and appealed the matter to the U.S. Court of Appeals for the Tenth Circuit. Shortly thereafter, the EPA withdrew its letter. In response, we dismissed the appeal. At this time, no further proceedings are expected.

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Litigation Related to the Merger with Frontier Oil Corporation

Twelve substantially similar shareholder lawsuits styled as class actions were filed by purported Frontier shareholders challenging our proposed “merger of equals” with Frontier and naming as defendants Frontier, its board of directors and, in certain instances, Holly and our wholly owned subsidiary, North Acquisition, Inc., as aiders and abettors. To date, such shareholder actions remain pending in the U.S. District Court for the Northern District of Texas, and the U.S. District Court for the Southern District of Texas. One case filed in Laramie County, Wyoming was dismissed without prejudice. Final judgment was entered by the Court in the consolidated Harris County, Texas cases on January 6, 2012, dismissing with prejudice all claims made by the class members.

These lawsuits generally allege that (1) the consideration received by Frontier’s shareholders in the merger was inadequate, (2) the Frontier directors breached their fiduciary duties by, among other things, approving the merger at an inadequate price under circumstances involving certain alleged conflicts of interest, (3) the merger agreement includes preclusive deal protection provisions, and (4) Frontier, and in some cases we and North Acquisition, Inc., aided and abetted Frontier’s directors in breaching their fiduciary duties to Frontier’s shareholders. In the three federal court cases discussed more fully below, we and/or North Acquisition, Inc. were also alleged to have violated Section 14(a) and Section 20(a) of the Exchange Act of 1934 by soliciting proxies based on an allegedly false and/or misleading proxy statement concerning the merger.

The eight lawsuits filed in the District Courts of Harris County, Texas (the “Texas State Court Lawsuits”) were consolidated on March 25, 2011, under the caption: In re Frontier Oil Corporation, Cause No. 2011-11451 (first case filed February 22, 2011), and Interim Class Counsel was appointed on April 12, 2011. On September 12, 2011, the lead plaintiff and the defendants in the Texas State Court Lawsuits submitted a Stipulation and Agreement of Settlement to the Court for preliminary approval. Pursuant to that agreement, the actions were stayed and certain additional disclosures were made to Frontier’s shareholders on June 20, 2011. After a hearing on October 7, 2011, the Court granted preliminary approval of the settlement and scheduled a final settlement hearing for January 6, 2012. On January 6, 2012, the Court approved a settlement and certified an opt-out class action, dismissed with prejudice all claims released by the terms of the settlement, and awarded attorneys’ fees and costs in the amount of $612,500 to counsel for the lead plaintiffs. Shareholders who objected to the settlement may appeal the Court’s decision to overrule their objections. On January 19, 2012, one shareholder, whose objection related solely to the award of attorneys’ fees, filed a request for findings of fact and conclusions of law and a motion for new trial. Generally, in the event that the order is reversed or modified on appeal, counsel for the lead plaintiffs shall refund the fee award consistent with such reversal or modification.

The lawsuit filed in the U.S. District Court for the Northern District of Texas is styled Angelo Chiarelli v. Holly Corporation, et al. (filed on March 2, 2011). On June 29, 2011, the plaintiff filed an amended complaint, and one month later, the parties filed an agreed motion to stay the case so that the proposed settlement in the Texas State Court Lawsuits could be considered and resolved by the state court. The motion to stay was granted on August 8, 2011. On January 30, 2012, the parties filed a joint report informing the Court that the settlement in the Texas State Court Lawsuits had been approved and entered, that all claims in the Texas State Court Lawsuits had been dismissed, and that Chiarelli neither objected to the settlement nor opted out of the class.

The two remaining lawsuits filed in the U.S. District Court for the Southern District of Texas are consolidated under the caption: Tim Wilcox v. Frontier Oil Corporation, et al. (first case filed on March 7, 2011). We and our wholly owned subsidiary moved to dismiss the amended complaint on April 21, 2011, and the other defendants moved for dismissal in July after they were served. On June 24, 2011, the court denied plaintiffs’ motion for a temporary restraining order and preliminary injunction to enjoin the proposed merger and prevent Frontier’s shareholders from voting on it. On August 9, 2011, the defendants filed an unopposed motion to stay the consolidated case in light of the proposed settlement of the Texas State Court Lawsuits. On November 29, 2011, the court granted defendants’ unopposed motion to stay and ordered the parties to file a report on the status of the proposed settlement of the Texas State Court Lawsuits by January 13, 2012. That same day, the court denied defendants’ motions to dismiss without prejudice to refile. On January 13, 2012, the parties filed a joint report informing the Court that the settlement in the Texas State Court Lawsuits had been approved and entered and that all claims in the Texas State Court Lawsuits had been dismissed.

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Due to recent developments we no longer believe these matters are material and, accordingly, they will not be disclosed in future SEC filings.

Unclaimed Property Audits

A multi-state audit of legacy Holly Corporation’s unclaimed property compliance and reporting is being conducted by Kelmar Associates, LLC on behalf of eleven states. We are currently in the fourth year of this ongoing audit that covers the period 1981 – 2004. It is not yet possible to accurately estimate the amount, if any, that is owed to each of the states.

A similar multi-state audit of legacy Frontier Oil Corporation’s unclaimed property compliance and reporting is also being conducted by Kelmar Associates, LLC on behalf of five states. The audit work began in December 2011. It is not yet possible to accurately estimate the amount, if any, that might be owed to each of the states participating in this audit.

We have determined that these audits are not material to the Company so they will no longer be reported in our SEC filings.

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
2011
Fourth quarter	$	35.00	$	21.13	$	0.600		243,985,000
Third quarter	$	38.90	$	24.25	$	0.588		261,573,400
Second quarter	$	34.94	$	25.30	$	0.075		212,391,800
First quarter	$	31.61	$	19.92	$	0.075		149,825,800

2010
Fourth quarter	$	20.69	$	14.10	$	0.075		73,805,800
Third quarter	$	14.93	$	12.18	$	0.075		74,987,200
Second quarter	$	15.29	$	11.66	$	0.075		126,628,400
First quarter	$	15.43	$	12.57	$	0.075		95,424,800

Under our common stock repurchase program repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. The following table includes repurchases made under this program during the fourth quarter of 2011.


Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased under Approved Stock Repurchase Program		Maximum Dollar Value of Shares Yet to be Purchased under Approved Stock Repurchase Program
October 2011		125,523	$	26.63		586,123	$	82,156,066
November 2011		—	$	—		—	$	82,156,066
December 2011		—	$	—		—	$	82,156,066

Total		125,523				586,123

Additionally during the three months ended December 31, 2011, we withheld 18,322 shares of our common stock from certain executives and employees in the amount of $0.5 million. These withholdings were made under the terms of our share-based compensation unit agreements to provide funds for the payment of payroll and income taxes due at vesting in the case of officers and employees who did not elect to satisfy such taxes by other means.

As of February 16, 2012, we had approximately 48,000 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 13 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”

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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,
	2011			2010			2009			2008			2007
	(In thousands, except per share data)
FINANCIAL DATA⁽¹⁾⁽²⁾
For the period
Sales and other revenues	$	15,439,528		$	8,322,929		$	4,834,268		$	5,860,357		$	4,791,742
Income from continuing operations before income taxes		1,641,695			192,363			43,803			187,746			499,444
Income tax provision		581,991			59,312			7,460			64,028			165,316

Income from continuing operations		1,059,704			133,051			36,343			123,718			334,128
Income from discontinued operations, net of taxes⁽³⁾		—			—			16,926			2,918			—

Net income		1,059,704			133,051			53,269			126,636			334,128
Less net income attributable to noncontrolling interest		36,307			29,087			33,736			6,078			—


Net income attributable to HollyFrontier stockholders	$	1,023,397		$	103,964		$	19,533		$	120,558		$	334,128

Earnings per share attributable to HollyFrontier stockholders – basic	$	6.46		$	0.98		$	0.20		$	1.20		$	3.05
Earnings per share attributable to HollyFrontier stockholders – diluted	$	6.42		$	0.97		$	0.20		$	1.19		$	2.99
Cash dividends declared per common share	$	1.34		$	0.30		$	0.30		$	0.30		$	0.23
Average number of common shares outstanding:
Basic		158,486			106,436			100,836			100,404			109,704
Diluted		159,294			107,218			101,206			101,098			111,700
Net cash provided by operating activities	$	1,338,391		$	283,255		$	211,545		$	155,490		$	422,737
Net cash provided by (used for) investing activities	$	228,494		$	(213,232	)	$	(534,603	)	$	(57,777	)	$	(293,057	)
Net cash provided by (used for) financing activities	$	(217,082	)	$	34,482		$	406,849		$	(151,277	)	$	(189,428	)

At end of period
Cash, cash equivalents and investments in marketable securities	$	1,840,610		$	230,444		$	125,819		$	94,447		$	329,784
Working capital	$	2,030,063		$	313,580		$	257,899		$	68,465		$	216,541
Total assets	$	10,314,621		$	3,701,475		$	3,145,939		$	1,874,225		$	1,663,945
Total debt, including short-term⁽⁴⁾	$	1,214,742		$	810,561		$	707,458		$	370,914		$	—
Total equity	$	5,835,900		$	1,288,139		$	1,207,781		$	936,332		$	602,127

(1)	We merged with Frontier effective 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)

We reconsolidated HEP effective March 1, 2008 and include the consolidated results of HEP in our financial statements. For the period from July 1, 2005 through February 29, 2008, we accounted for our investment in HEP under the equity method of accounting whereby we recorded our pro-rata share of earnings in HEP and contributions to and distributions from HEP were recorded as adjustments to our investment balance. See “Company Overview” under Items 1 and 2, “Business and Properties” for information regarding our reconsolidation of HEP effective March 1, 2008.

(3)	On December 1, 2009, HEP sold its 70% interest in Rio Grande. Results of operations of Rio Grande that were previously reported in operations are presented in discontinued operations.

(4)	Includes total HEP debt of $525.9 million, $482.3 million, $379.2 million and $370.9 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 effective 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 operate five 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).

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. Concurrent with the merger, we changed our name to HollyFrontier Corporation and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Subsequent to the merger and following approval by the post-closing board of directors of HollyFrontier, Frontier merged with and into HollyFrontier, with HollyFrontier continuing as the surviving corporation. This merger combined the legacy Frontier refinery operations, the El Dorado and Cheyenne Refineries, with Holly’s legacy refinery operations to form HollyFrontier.

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 equity consideration paid in connection with the merger was $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.

In June 2009, we acquired the Tulsa West facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco and in December 2009, acquired the Tulsa East facility, a 75,000 BPSD refinery from Sinclair also located in Tulsa, Oklahoma. We have integrated certain operations of the Tulsa Refineries, resulting in a combined crude processing rate of 125,000 BPSD.

Sales and other revenues and net income attributable to HollyFrontier stockholders were $15,439.5 million and $1,023.4 million, $8,322.9 million and $104 million, and $4,834.3 million and $19.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses were $13,708 million, $8,059.9 million and $4,754 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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RESULTS OF OPERATIONS

Financial Data


	Years Ended December 31,
	2011⁽¹⁾			2010			2009⁽²⁾
	(In thousands, except per share data)
Sales and other revenues	$	15,439,528		$	8,322,929		$	4,834,268
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		12,680,078			7,367,149			4,238,008
Operating expenses (exclusive of depreciation and amortization)		748,081			504,414			356,855
General and administrative expenses (exclusive of depreciation and amortization)		120,114			70,839			60,343
Depreciation and amortization		159,707			117,529			98,751

Total operating costs and expenses		13,707,980			8,059,931			4,753,957


Income from operations		1,731,548			262,998			80,311
Other income (expense):
Earnings of equity method investments		2,300			2,393			1,919
Interest income		1,284			1,168			5,045
Interest expense		(78,323	)		(74,196	)		(40,346	)
Merger transaction costs		(15,114	)		—			—
Acquisition costs – Tulsa refineries		—			—			(3,126	)

		(89,853	)		(70,635	)		(36,508	)


Income from continuing operations before income taxes		1,641,695			192,363			43,803
Income tax provision		581,991			59,312			7,460

Income from continuing operations		1,059,704			133,051			36,343
Income from discontinued operations, net of taxes⁽³⁾		—			—			16,926


Net income		1,059,704			133,051			53,269
Less net income attributable to noncontrolling interest		36,307			29,087			33,736

Net income attributable to HollyFrontier stockholders	$	1,023,397		$	103,964		$	19,533


Earnings attributable to HollyFrontier stockholders:
Income from continuing operations	$	1,023,397		$	103,964		$	15,209
Income from discontinued operations		—			—			4,324

Net income	$	1,023,397		$	103,964		$	19,533


Earnings per share attributable to HollyFrontier stockholders – basic:
Income from continuing operations	$	6.46		$	0.98		$	0.15
Income from discontinued operations		—			—			0.05

Net income	$	6.46		$	0.98		$	0.20


Earnings per share attributable to HollyFrontier stockholders – diluted:
Income from continuing operations	$	6.42		$	0.97		$	0.15
Income from discontinued operations		—			—			0.05

Net income	$	6.42		$	0.97		$	0.20


Cash dividends declared per common share	$	1.34		$	0.30		$	0.30


Average number of common shares outstanding:
Basic		158,486			106,436			100,836
Diluted		159,294			107,218			101,206

(1)	Effective July 1, 2011, our consolidated financial and operating results reflect the operations of the merged Frontier businesses. Assuming the merger had been consummated on January 1, 2010, pro forma revenues and net income are as follows:


	Year Ended December 31,
	2011		2010
	(In thousands)
Sales and other revenues	$	19,418,709	$	14,207,835
Net income attributable to HollyFrontier stockholders	$	1,335,257	$	179,979

(2)	We acquired the Tulsa Refineries in 2009. Our consolidated financial and operating results reflect the operations of the Tulsa West facility effective June 1, 2009 and the Tulsa East facility effective December 1, 2009.

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

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Balance Sheet Data


	December 31,
	2011		2010
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	1,840,610	$	230,444
Working capital	$	2,030,063	$	313,580
Total assets	$	10,314,621	$	3,701,475
Long-term debt – HollyFrontier Corporation	$	688,882	$	328,290
Long-term debt – Holly Energy Partners	$	525,860	$	482,271
Total equity	$	5,835,900	$	1,288,139

Other Financial Data


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Net cash provided by operating activities	$	1,338,391		$	283,255		$	211,545
Net cash provided by (used for) investing activities	$	228,494		$	(213,232	)	$	(534,603	)
Net cash provided by (used for) financing activities	$	(217,082	)	$	34,482		$	406,849
Capital expenditures	$	374,241		$	213,232		$	302,551
EBITDA from continuing operations⁽¹⁾	$	1,842,134		$	353,833		$	156,721

(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 currently 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 Eliminations.


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Sales and other revenues
Refining⁽¹⁾	$	15,392,430		$	8,287,000		$	4,789,821
HEP⁽²⁾		213,566			182,114			146,561
Corporate and other		1,247			415			(636	)
Eliminations		(167,715	)		(146,600	)		(101,478	)

Consolidated	$	15,439,528		$	8,322,929		$	4,834,268


Operating income (loss)
Refining⁽¹⁾	$	1,739,068		$	242,466		$	71,281
HEP⁽²⁾		113,258			92,386			70,373
Corporate and other		(120,833	)		(69,654	)		(60,239	)
Eliminations		55			(2,200	)		(1,104	)

Consolidated	$	1,731,548		$	262,998		$	80,311

(1)

The Refining segment includes the operations of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt and involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. The petroleum products are primarily marketed in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and northern Mexico. Additionally, specialty lubricant products produced at our Tulsa West facility are marketed throughout North America and are distributed in Central and South America. NK Asphalt manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico.

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(2)

The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates logistic 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. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through its pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Additionally, HEP owns a 25% interest in the SLC Pipeline that serves refineries in the Salt Lake City, Utah area. 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.

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 margin 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,
	2011⁽¹⁰⁾			2010			2009 ⁽¹¹⁾
Consolidated
Crude charge (BPD)⁽¹⁾		315,000			221,440			142,430
Refinery throughput (BPD) ⁽²⁾		340,200			234,910			154,940
Refinery production (BPD) ⁽³⁾		331,890			225,980			151,420
Sales of produced refined products (BPD)		332,720			228,140			151,580
Sales of refined products (BPD) ⁽⁴⁾		340,630			232,100			155,820

Refinery utilization ⁽⁵⁾		89.9	%		86.5	%		78.9	%

Average per produced barrel ⁽⁶⁾
Net sales	$	118.82		$	91.06		$	74.06
Cost of products ⁽⁷⁾		98.18			82.27			66.85

Refinery gross margin		20.64			8.79			7.21
Refinery operating expenses ⁽⁸⁾		5.36			5.08			5.24

Net operating margin	$	15.28		$	3.71		$	1.97

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.24		$	4.94		$	5.12

(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). During 2009, we increased our consolidated crude capacity by 15,000 BPSD effective April 1, 2009 (our Navajo Refinery expansion), by 85,000 BPSD effective June 1, 2009 (our Tulsa West facility acquisition) and by 40,000 BPSD effective December 1, 2009 (our Tulsa East facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD. As a result of our merger effective July 1, 2011 we increased our crude capacity by 135,000 BPSD with the El Dorado Refinery and by 52,000 with the addition of our Cheyenne Refinery for a consolidated total of 443,000 BPSD.

(6)

(7)	Transportation costs billed from HEP are included in cost of products.

(8)	Represents operating expenses of the refineries, exclusive of depreciation and amortization.

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

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(10)	Refining operating data for the year ended December 31, 2011 includes 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 for the year ended December 31, 2011.

(11)	Refining operating data for the year ended December 31, 2009 includes crude oil processed and products yielded from the Tulsa Refineries for the period from June 1, 2009 through December 31, 2009 only, and averaged over the 365 days for the year ended December 31, 2009.

Results of Operations – Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Summary

Net income attributable to HollyFrontier Corporation stockholders for the year ended December 31, 2011 was $1,023.4 million ($6.46 per basic and $6.42 per diluted share) a $919.4 million increase compared to $104 million ($0.98 per basic and $0.97 per diluted share) for the year ended December 31, 2010. Net income increased due principally to earnings attributable to the merged Frontier business operations (principally, El Dorado and Cheyenne Refineries) which are included in our results beginning July 1, 2011, and due to significantly higher refinery gross margins during 2011. Overall refinery gross margins for the year ended December 31, 2011 were $20.64 per produced barrel compared to $8.79 for the year ended December 31, 2010.

Overall production levels for the year ended December 31, 2011 increased by 47% over 2010 due to the inclusion of the El Dorado and Cheyenne Refinery operations following our merger with Frontier effective July 1, 2011.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 86% from $8,322.9 million for the year ended December 31, 2010 to $15,439.5 million for the year ended December 31, 2011, due principally to the inclusion of $4,183.8 million in revenues attributable to the El Dorado and Cheyenne Refinery operations and the effects of increased refined product sales prices over the prior year. The average sales price we received per produced barrel sold increased 30% from $91.06 for the year ended December 31, 2010 to $118.82 for the year ended December 31, 2011. Sales and other revenues for the years ended December 31, 2011 and 2010, include $46.4 million and $36 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 72% from $7,367.1 million for the year ended December 31, 2010 to $12,680.1 million for the year ended December 31, 2011, due principally to the inclusion of results from the El Dorado and Cheyenne Refinery operations, and due to higher crude oil costs. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 19% from $82.27 for the year ended December 31, 2010 to $98.18 for the year ended December 31, 2011.

Gross Refinery Margins

Gross refining margin per produced barrel increased 135% from $8.79 for the year ended December 31, 2010 to $20.64 for the year ended December 31, 2011, due to an increase in the average sales price we received per produced barrel sold, partially offset by an increase in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include the effects of depreciation or 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 costs of products purchased.

Operating Expenses

Operating expenses, exclusive of depreciation and amortization increased 48% from $504.4 million for the year ended December 31, 2010 to $748.1 million for the year ended December 31, 2011, due principally to costs attributable to the El Dorado and Cheyenne Refinery operations. Also contributing to a much lesser extent were increased payroll and maintenance costs attributable to the legacy Holly refining operations. For the years ended December 2011 and 2010, operating expenses include $61.7 million and $52.4 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses

General and administrative expenses increased 70% from $70.8 million for the year ended December 31, 2010 to $120.1 million for the year ended December 31, 2011. This includes $26.5 million in integration and severance costs

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associated with the merger integration. It also reflects higher payroll, equity based compensation costs and support costs for our larger organization. For the years ended December 31, 2011 and 2010, general and administrative expenses include $4.3 million and $5.4 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 36% from $117.5 million for the year ended December 31, 2010 to $159.7 million for the year ended December 31, 2011. The increase was due principally to depreciation and amortization attributable to the El Dorado and Cheyenne Refinery operations and capitalized improvement projects. For the years ended December 31, 2011 and 2010, depreciation and amortization expenses include $31.5 million and $29.1 million, respectively, in costs attributable to HEP operations.

Interest Income

Interest income for the year ended December 31, 2011 was $1.3 million compared to $1.2 million for the year ended December 31, 2010. For the year ended December 31, 2011, interest income reflects higher cash investment levels in 2011. Additionally, interest income for the year ended December 31, 2010 reflects interest received on income tax refunds.

Interest Expense

Interest expense was $78.3 million for the year ended December 31, 2011 compared to $74.2 million for the year ended December 31, 2010. This increase reflects the write-off of $5 million of previously deferred financing costs due to the July 1, 2011 termination of our previous credit agreement and the inclusion of interest attributable to the senior notes assumed upon our merger with Frontier. Additionally, during 2011 we capitalized $17.2 million in interest attributable to construction projects. For the years ended December 31, 2011 and 2010, interest expense included $38.2 million and $36.3 million, respectively, in 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 effective July 1, 2011. These costs relate to legal, advisory and other professional fees that are directly attributable to the merger.

Income Taxes

Income taxes increased from $59.3 million for the year ended December 31, 2010 to $582 million for the year ended December 31, 2011 due to significantly higher pre-tax earnings for the year ended December 31, 2011 compared to 2010. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 35.5% for the year ended December 31, 2011 compared to 30.8% for the year ended December 31, 2010. 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. Our actual tax rate for income tax purposes did not increase.

Results of Operations – Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Summary

Net income attributable to HollyFrontier Corporation stockholders for the year ended December 31, 2010 was $104 million ($0.98 per basic and $0.97 per diluted share) an $84.4 million increase compared to $19.5 million ($0.20 per basic and diluted share) for the year ended December 31, 2009. Net income increased due principally to increased sales volumes of produced refined products combined with higher refinery gross margins during 2010. Overall refinery gross margins for the year ended December 31, 2010 were $8.79 per produced barrel compared to $7.21 for the year ended December 31, 2009.

Overall production levels for the year ended December 31, 2010 increased by 49% over 2009 due to production from our Tulsa Refineries acquired in June and December 2009 combined with production increases at our Navajo and Woods Cross Refineries. Additionally, 2009 levels reflect lower production during the first quarter of 2009 due to scheduled downtime during a planned major maintenance turnaround at our Navajo Refinery.

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Sales and Other Revenues

Sales and other revenues from continuing operations increased 72% from $4,834.3 million for the year ended December 31, 2009 to $8,322.9 million for the year ended December 31, 2010, due principally to the effects of a 51% increase in year-over-year volumes of produced refined products sold combined with increased sales prices of produced refined products. The average sales price we received per produced barrel sold increased 23% from $74.06 for the year ended December 31, 2009 to $91.06 for the year ended December 31, 2010. Sales and other revenues for the years ended December 31, 2010 and 2009, include $35.7 million and $45.2 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 74% from $4,238 million for the year ended December 31, 2009 to $7,367.1 million for the year ended December 31, 2010, due principally to higher crude oil costs combined with a 51% increase in volumes of produced refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 23% from $66.85 for the year ended December 31, 2009 to $82.27 for the year ended December 31, 2010.

Gross Refinery Margins

Gross refining margin per produced barrel increased 22% from $7.21 for the year ended December 31, 2009 to $8.79 for the year ended December 31, 2010, due to an increase in the average sales price we received per produced barrel sold, partially offset by an increase in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include the effects of depreciation or amortization.

Operating Expenses

Operating expenses, exclusive of depreciation and amortization increased 41% from $356.9 million for the year ended December 31, 2009 to $504.4 million for the year ended December 31, 2010, due principally to costs attributable to the operations of our Tulsa Refineries acquired in June and December 2009 and higher refinery utility costs. For the years ended December 2010 and 2009, operating expenses include $52.4 million and $43.5 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses

General and administrative expenses increased 17% from $60.3 million for the year ended December 31, 2009 to $70.8 million for the year ended December 31, 2010, due principally to costs associated with the support and integration of our Tulsa operations and increased payroll costs. For the years ended December 31, 2010 and 2009, general and administrative expenses include $5.4 million and $5.3 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 19% from $98.8 million for the year ended December 31, 2009 to $117.5 million for the year ended December 31, 2010. The increase was due principally to depreciation and amortization attributable to our Tulsa facilities and capitalized refinery improvement projects in 2009 and 2010. For the years ended December 31, 2010 and 2009, depreciation and amortization expenses include $29.1 million and $26.5 million, respectively, in costs attributable to HEP operations.

Interest Income

Interest income for the year ended December 31, 2010 was $1.2 million compared to $5 million for the year ended December 31, 2009. Interest income was higher for the year ended December 31, 2009 due to interest received on income tax refunds and investments in higher yield marketable debt securities.

Interest Expense

Interest expense was $74.2 million for the year ended December 31, 2010 compared to $40.3 million for the year ended December 31, 2009. The increase was due principally to interest incurred on our $300 million 9.875% senior notes issued in 2009 and HEP’s 8.25% senior notes issued in March 2010. For the years ended December 31, 2010 and 2009, interest expense included $36.3 million and $23.8 million, respectively, in costs attributable to HEP operations.

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Income Taxes

Income taxes increased from $7.5 million for the year ended December 31, 2009 to $59.3 million for the year ended December 31, 2010 due to significantly higher pre-tax earnings for the year ended December 31, 2010 compared to 2009. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 30.8% for the year ended December 31, 2010 compared to 17% for the year ended December 31, 2009. 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. Our actual tax rate for income tax purposes did not increase.

Discontinued Operations

On December 1, 2009, HEP sold its 70% interest in Rio Grande resulting in a $14.5 million gain. Rio Grande operations generated net earnings of $4.4 million for the year ended December 31, 2009 before taking into account HEP’s noncontrolling interest in the discontinued operations.

LIQUIDITY AND CAPITAL RESOURCES

HollyFrontier Credit Agreement

On July 1, 2011, we entered into a $1 billion senior secured credit agreement (the “HollyFrontier Credit Agreement”) with Union Bank, N.A. as administrative agent and BNP Paribas as syndication agent, and certain lenders from time to time party thereto, and terminated our previous $400 million credit agreement. Additionally, Frontier terminated its previous $500 million credit agreement. The HollyFrontier Credit Agreement matures in July 2016 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.

We were in compliance with all covenants at December 31, 2011. At December 31, 2011, we had no outstanding borrowings and outstanding letters of credit totaled $6.1 million under the HollyFrontier Credit Agreement. The unused commitment available under this credit agreement was $993.9 million at December 31, 2011.

HEP Credit Agreement

At December 31, 2011, HEP had a $275 million senior secured revolving credit facility expiring in February 2016 (the “HEP Credit Agreement”) with an outstanding balance of $200 million. On February 3, 2012, the HEP Credit Agreement was amended, increasing the size of the credit facility from $275 million to $375 million (the “HEP Amended 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 and to fund distributions to unitholders up to a $30 million sub-limit. The HEP Amended Credit Agreement expires in February 2016; however, in the event that the 6.25% HEP Senior Notes (discussed later) are not repurchased, defeased, refinanced, extended or repaid prior to September 1, 2014, the HEP Amended Credit Agreement will expire on that date.

HEP’s obligations under the HEP Amended Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our Consolidated Balance Sheets). Indebtedness under the HEP Amended Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and 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 other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

HollyFrontier Senior Notes

Our senior notes consist of the following:

•

9.875% Senior Notes ($291.8 million principal amount maturing June 2017)

•

6.875% Senior Notes ($150 million principal amount maturing November 2018)⁽¹⁾

•

8.5% Senior Notes ($200 million principal amount maturing September 2016)⁽¹⁾

⁽¹⁾ Represent senior notes assumed upon our July 1, 2011 merger with Frontier.

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In June 2009, we issued $200 million in aggregate principal amount of the 9.875% Senior Notes maturing June 15, 2017. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the 9.875% Senior Notes.

We have additional senior notes that we assumed as a result of our July 1, 2011 merger with Frontier; the 6.875% Senior Notes having an aggregate principal amount of $150 million maturing November 15, 2018 and the 8.5% Senior Notes having an aggregate principal amount of $200 million maturing September 15, 2016.

These senior notes (collectively, 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. At any time when 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 will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes.

HollyFrontier Financing Obligation

In October 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa West facility as well as certain crude oil pipeline receiving facilities to an affiliate of Plains for $40 million in cash. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits with Plains for crude oil purchased by them and delivered to our Tulsa West facility for storage. Due to our continuing involvement in these assets, this sales and lease transaction has been accounted for as a financing obligation. As a result, we retained these assets on our books and recorded a liability representing the $40 million in proceeds received.

HEP Senior Notes

HEP’s senior notes consist of the following:

•

6.25% HEP Senior Notes ($185 million principal amount maturing March 2015)

•

8.25% HEP Senior Notes ($150 million principal amount maturing March 2018)

In March 2010, HEP issued $150 million in aggregate principal amount of 8.25% HEP Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund HEP’s $93 million purchase of certain storage assets at our Tulsa East facility and Navajo Refinery Lovington facility on March 31, 2010. Additionally, HEP used a portion to repay $42 million in outstanding HEP Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.

HEP also has $185 million in aggregate principal amount of 6.25% HEP Senior Notes maturing March 1, 2015 that are registered with the SEC.

These 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.

Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general partner, and 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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See “Risk Management” for a discussion of HEP’s interest rate swap contracts.

HEP Common Unit Issuances

2011 Issuances

In December 2011, HEP issued 1,475,000 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 9, 2011 asset acquisition from us. This repayment to us is eliminated in our consolidated financial statements.

In November 2011, HEP issued 3,807,615 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.

2009 Issuances

In December 2009, HEP issued 1,373,609 of its common units having a value of $53.5 million to Sinclair as partial consideration of its purchase of Sinclair’s Tulsa logistics assets.

In November 2009, HEP issued 2,185,000 of its common units priced at $35.78 per unit. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s December 1, 2009 asset acquisitions, to repay outstanding borrowings under HEP’s credit agreement and for general partnership purposes.

Additionally in May 2009, HEP issued 2,192,400 of its common units priced at $27.80 per unit. Net proceeds of $58.4 million were used to repay outstanding borrowings under HEP’s credit agreement and for general partnership purposes.

Liquidity

We believe our current available cash on hand, 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. Our ability to acquire complementary assets will be dependent upon several 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 many other factors beyond our control.

As of December 31, 2011, our cash, cash equivalents and investments in marketable securities totaled $1.8 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, and are invested primarily in conservative, highly-rated instruments issued by government or municipal entities with strong credit standings.

In September 2011, our Board of Directors approved a stock repurchase program of up to $100 million to repurchase common stock in the open market or through privately negotiated transactions. As of December 31, 2011, we had repurchased 586,123 shares at a cost of $17.8 million under this stock repurchase program.

In January 2012, our Board of Directors approved a $350 million stock repurchase program, which replaced the existing $100 million stock repurchase program. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. The stock repurchase program may be discontinued at any time by the Board of Directors.

Cash and cash equivalents increased by $1,349.8 million during the year ended December 31, 2011. Net cash provided by operating activities and investing activities of $1,338.4 million and $228.5 million, respectively, exceeded cash used for financing activities of $217.1 million. Working capital increased by $1,716.5 million during 2011.

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Cash Flows—Operating Activities

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net cash flows provided by operating activities were $1,338.4 million for the year ended December 31, 2011 compared to $283.3 million for the year ended December 31, 2010, an increase of $1,055.1 million. Net income for the year ended December 31, 2011 was $1,059.7 million, an increase of $926.6 million from $133.1 million for the year ended December 31, 2010. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense and derivative instrument adjustments resulted in an increase to operating cash flows of $178 million for the year ended December 31, 2011 compared to $154.3 million for the year ended December 31, 2010. Additionally, earnings of our equity method investments, net of distributions, increased operating cash flows by $0.4 million for the year ended December 31, 2011 compared to $0.5 million for the year ended December 31, 2010. Changes in working capital items increased cash flows by $147.3 million in 2011 compared to $24.7 million in 2010. For the year ended December 31, 2011, inventories increased by $56.8 million compared to $96.9 million for 2010. Also for 2011, accounts receivable decreased by $286.7 million compared to an increase of $228.5 million for 2010 and accounts payable decreased by $164.6 million compared to an increase of $342.2 million for 2010. Additionally, turnaround expenditures were $32 million and $35 million for the years ended December 31, 2011 and 2010, respectively.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Net cash flows provided by operating activities were $283.3 million for the year ended December 31, 2010 compared to $211.5 million for the year ended December 31, 2009, an increase of $71.8 million. Net income for the year ended December 31, 2010 was $133.1 million, an increase of $79.8 million from $53.3 million for the year ended December 31, 2009. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense, gain on sale of assets and interest rate swap adjustments resulted in an increase to operating cash flows of $154.3 million for the year ended December 31, 2010 compared to $130.4 million for the year ended December 31, 2009. Additionally, SLC Pipeline earnings, net of distributions, increased operating cash flows by $0.5 million for the year ended December 31, 2010 compared to a $0.4 million decrease for the year ended December 31, 2009. Changes in working capital items increased cash flows by $24.7 million in 2010 compared to $44 million in 2009. For the year ended December 31, 2010, inventories increased by $96.9 million compared to $17.9 million for 2009. Also for 2010, accounts receivable increased by $228.5 million compared to $474.2 million for 2009 and accounts payable increased by $342.2 million compared to $583.6 million for 2009. Additionally, turnaround expenditures were $35 million and $33.5 million for the years ended December 31, 2010 and 2009, respectively.

Cash Flows—Investing Activities and Planned Capital Expenditures

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net cash flows provided by investing activities were $228.5 million for the year ended December 31, 2011 compared to net cash flows used for investing activities $213.2 million for the year ended December 31, 2010, an increase of $441.7 million. Current year investing activities 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, plant and equipment for 2011 increased to $374.2 million compared to $213.2 million for 2010. These include HEP capital expenditures of $39.3 million and $25.1 million for the years ended December 31, 2011 and 2010, respectively. Current year capital expenditures include $164.3 million in costs to construct the UNEV Pipeline, which was mechanically complete in November 2011. During the year ended December 31, 2011, we invested $9.1 million in Sabine Biofuels, a development stage biodiesel production facility. Additionally for the year ended December 31, 2011, we invested $561.9 million in marketable securities and received proceeds of $301 million from the sale of our marketable securities.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Net cash flows used for investing activities were $213.2 million for the year ended December 31, 2010 compared to $534.6 million for the year ended December 31, 2009, a decrease of $321.4 million. Cash expenditures for properties, plant and equipment for 2010 decreased to $213.2 million compared to $302.6 million for 2009. These include HEP capital expenditures of $25.1 million and $33 million for the years ended December 31, 2010 and 2009, respectively. Capital expenditures were significantly lower in 2010 due to a higher level of capital project initiatives in 2009 including refinery expansion projects. During the year ended December 31, 2009, we paid cash

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consideration of $267.1 million in connection with the Tulsa West and East facility acquisitions, invested $175.9 million in marketable securities and received proceeds of $230.3 million from the sale or maturity of marketable securities. Additionally, HEP acquired logistics and storage assets from an affiliate of Sinclair for $25.7 million and made a $25.5 million joint venture contribution to the SLC Pipeline. In December 2009, HEP sold its 70% interest in Rio Grande for $35 million. The cash proceeds received are presented net of Rio Grande’s December 1, 2009 cash balance of $3.1 million.

Planned Capital Expenditures

HollyFrontier Corporation

Each year our Board of Directors approves our annual capital budget which includes specific projects that our 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 2012 is $257 million including both sustaining capital and major capital projects. We expect to spend approximately $350 million in cash for capital projects in 2012, including projects approved in prior years. In addition, we expect to spend $120 million on refinery turnarounds and tank maintenance. Refinery turnaround spending is amortized over the useful life of the turnaround while tank maintenance is expensed as incurred. Our new capital appropriation for 2012 and expected cash spending are as follows:


	Capital Budget (New Appropriation)		Expected Capital Spending (Cash)
	(In millions)
Location:
El Dorado	$	87	$	55
Tulsa		49		101
Navajo		26		38
Cheyenne		76		46
Woods Cross		10		85
UNEV		—		16
Corporate and Other		9		9

Total	$	257	$	350


Type:
Sustaining	$	74	$	68
Reliability and Growth		71		132
Compliance and Safety		112		150

Total	$	257	$	350

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 FCCU flu 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

Newly appropriated capital projects at the El Dorado Refinery include naphtha splitting and aromatics recovery unit revamps to reduce benzene in gasoline (MSAT2 compliance) and installation of a new tail gas treatment unit with our sulfur recovery facilities as required under an existing EPA consent decree. Also included in the 2012 capital budget are yield improvement projects that address both the FCC unit and the Coker. A previously appropriated project which we expect to complete during 2012 is the replacement of an existing Coker furnace with more current furnace technology. This project is expected to improve Coker on-stream factor and reduce fuel consumption. We expect to complete this project in late 2012.

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Tulsa Refineries

The most significant newly appropriated capital project for our Tulsa Refineries is conversion of a propane de-asphalt unit to ROSE technology. This project is expected to cost $25 million and will increase processing of vacuum tower bottoms, increase the production of bright stock lube, reduce energy consumption, and allow the shutdown of a low-pressure steam boiler. Projects still underway from prior appropriations include a $58 million project to recover sulfur from the refinery fuel gas system and to shut down another low pressure steam boiler by electrification of turbine drivers. The sulfur recovery project is required to comply with our EPA consent decree but is being enhanced so as to increase our capacity to run lower priced sour / heavy crude in Tulsa. We are also executing an LPG recovery project in Tulsa at an estimated total cost of $28 million. This project will improve overall liquid yields and enable us to substitute lower-priced natural gas for LPG’s currently being consumed as refinery fuel. Other projects underway in Tulsa involve replacement of an existing vacuum tower and improvements to our wastewater treatment plants and storm water retention systems.

Navajo Refinery

We have approved a new project for the Navajo Refinery to remove sulfur and other contaminants from the crude unit off-gas stream; this will improve liquid yields and reduce refinery fuel costs. Current spending on previously appropriated projects includes an MSAT2 project (naphtha splitting and benzene saturation) to reduce reliance on benzene credits purchases, as well as expenditures to improve the Artesia waste water handling and processing facilities.

Cheyenne Refinery

We have approved four new compliance projects for the Cheyenne Refinery including wastewater treatment plant improvements, a wet gas scrubber for the FCC unit to reduce particulate and other emissions, MSAT2 related investments to reduced benzene in gasoline, and spending for additional tail gas unit associated with our sulfur recovery facilities. We also plan to improve metallurgy on portions of the Cheyenne Refinery’s delayed coking unit. These new major capital appropriations total approximately $60 million, and we expect to spend approximately 30% of this amount on these projects during 2012. Expenditures for MSAT2 compliance projects were accelerated by approximately one year at each of the Cheyenne and El Dorado Refineries due to the Holly-Frontier merger, this followed our loss of a small refiner exemption that previously provided for delayed compliance with this standard.

Woods Cross Refinery

We plan to significantly expand our Woods Cross Refinery in response to increased availability of locally-produced black wax crude oil. We have announced a 10-year crude supply agreement with Newfield Exploration Company under which we will purchase 20,000 bpd of waxy crudes (black and yellow wax). Our expansion project will increase crude processing capacity of Woods Cross from 31,000 bpd to 45,000 bpd. Most of the incremental crude supply is expected to be waxy crude, and the expansion is being configured to create high liquid yields and relatively large proportions of additional gasoline and diesel fuel in comparison to the increased crude charge. We expect this $225 million project to have a pre-tax payback period of approximately two years, and we expect to complete the expansion in approximately the fourth quarter of 2014. Our execution of this project is subject to certain contingencies, including our receipt of required emissions and other permits. Also at Woods Cross, we have two significant compliance projects authorized in prior year appropriations. The first of these involves installation of a wet gas scrubber on the FCC unit to reduce particulate and other emissions and the second relates to MSAT2 compliance which will require naphtha fractionation and benzene saturation.

UNEV

The UNEV Pipeline, in which we own a 75% equity interest, was mechanically completed in November 2011. Linefill and startup procedures commenced thereafter, and the pipeline and associated product terminals in Cedar City, Utah and Las Vegas, Nevada were operational during the first quarter of 2012. We believe that the UNEV Pipeline will play an important role in offsetting seasonal declines in product demand, characteristic of the Salt Lake City refined products market. We also believe that UNEV will facilitate a growing north-to-south flow of refined products which we expect will result from the advantaged crude oil economics enjoyed by PADD IV (Rocky Mountain) refiners. We plan to spend an additional $16 million in 2012 on capital items associated with the completion and startup of UNEV, and our estimate of total installed cost is now $308 million for our 75% interest in this pipeline.

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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 in order 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 2012 HEP capital budget is comprised of $8.9 million for maintenance capital expenditures and $25.8 million for expansion capital expenditures.

HEP has recently made certain modifications to its crude oil gathering and trunk line system that have effectively increased HEP’s ability to gather and transport an additional 10,000 bpd of Delaware Basin crude oil in response to increased drilling activity in southeast New Mexico. Furthermore, HEP has developed a project to replace a 5-mile section of this pipeline system that will allow for an additional 15,000 bpd of capacity that will be executed as needed if Delaware Basin crude volumes continue to increase. This project is estimated to cost approximately $2 million. HEP has a second project which consists of the reactivation and conversion to crude oil service of a 70-mile, 8-inch petroleum products pipeline owned by HEP. Once in service, this pipeline will initially be capable of transporting up to 35,000 bpd of crude oil from southeast New Mexico to third-party common carrier pipelines in west Texas for further transport to major crude oil markets. The scope of this project is being finalized. Subject to receipt of acceptable shipper support and board approval, this project could be operational in early 2013.

Cash Flows—Financing Activities

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net cash flows used by financing activities were $217.1 million for the year ended December 31, 2011 compared to cash flows provided by financing activities of $34.5 million for the year ended December 31, 2010, a decrease of $251.6 million. During 2011, we paid $8.2 million principal on our senior notes, paid $1.2 million under our financing obligation to Plains, purchased $42.8 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards and also under the stock repurchase program, paid $252.1 million in dividends, received a $33.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.8 million excess tax benefits on our equity based compensation. Also during this period, HEP received $75.8 million in net proceeds upon the issuance of HEP common units, received $118 million and repaid $77 million under the HEP Credit Agreement, paid distributions of $50.9 million to noncontrolling interests and purchased $1.6 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $11.8 million in deferred financing costs were incurred in connection with the amendment of HEP’s credit facility in February 2011 and a revision to the HollyFrontier Credit Agreement upon the merger with Frontier. We also incurred $0.6 million in costs associated with the issuance of HEP’s common units. During 2010, we received and repaid $310 million in advances under the HollyFrontier Credit Agreement, paid $1 million under our financing obligation to Plains, purchased $1.4 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $31.9 million in dividends, received a $23.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.1 million excess tax benefits on our equity based compensation. Also during this period, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $66 million and repaid $113 million under the HEP Credit Agreement, paid distributions of $48.5 million to noncontrolling interests and purchased $2.7 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs were incurred in connection with the issuance of the HEP 8.25% Senior Notes in March 2010 and an amendment to the HollyFrontier Credit Agreement.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Net cash flows provided by financing activities were $34.5 million for the year ended December 31, 2010 compared to $406.8 million for the year ended December 31, 2009, a decrease of $372.3 million. During 2010, we received

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and repaid $310 million in advances under the HollyFrontier Credit Agreement, paid $1 million under our financing obligation to Plains, purchased $1.4 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $31.9 million in dividends, received a $23.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.1 million excess tax benefits on our equity based compensation. Also during this period, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $66 million and repaid $113 million under the HEP Credit Agreement, paid distributions of $48.5 million to noncontrolling interests and purchased $2.7 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs were incurred in connection with the issuance of the HEP 8.25% Senior Notes in March 2010 and an amendment to the HollyFrontier Credit Agreement. During 2009, we received $287.9 million in net proceeds upon the issuance of the HollyFrontier 9.875% Senior Notes, received and repaid $94 million in advances under the HollyFrontier Credit Agreement, received $40 million under a financing transaction with Plains, paid $30.1 million in dividends, purchased $1.2 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, received a $15.2 million contribution from our UNEV Pipeline joint venture partner and recognized $1.2 million in excess tax benefits on our equity based compensation. Also during this period, HEP received proceeds of $133 million upon the issuance of additional common units, received $239 million and repaid $233 million in advances under the HEP Credit Agreement and paid distributions of $33.2 million to noncontrolling interests. Additionally, we paid $8.8 million in deferred financing costs during the year ended December 31, 2009 that relate to the HollyFrontier Senior Notes issued in June 2009.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2011 in total and by period due beginning in 2012. The table below does not include our contractual obligations to HEP under our long-term transportation agreements as these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.


			Payments Due by Period
Contractual Obligations and Commitments	Total		Less than 1 Year		2-3 Years		4-5 Years		Over 5 Years
	(In thousands)
HollyFrontier Corporation⁽¹⁾⁽²⁾
Long-term debt—principal⁽³⁾	$	679,433	$	1,309	$	3,143	$	204,002	$	470,979
Long-term debt—interest⁽⁴⁾		346,402		60,620		120,715		115,607		49,460
Supply agreements⁽⁵⁾		863,395		443,383		367,523		12,350		40,139
Transportation agreements⁽⁶⁾		510,924		79,348		153,750		127,847		149,979
Other long–term obligations		23,865		7,649		10,548		5,668		—
Operating leases		97,401		25,220		43,574		23,455		5,152

		2,521,420		617,529		699,253		488,929		715,709
Holly Energy Partners
Long-term debt—principal⁽⁷⁾		535,000		—		200,000		185,000		150,000
Long-term debt—interest⁽⁸⁾		137,684		29,530		59,060		30,531		18,563
Pipeline operating and right of way leases		36,954		6,668		13,274		13,217		3,795
Other agreements		15,303		1,381		2,692		2,364		8,866

		724,941		37,579		275,026		231,112		181,224

Total	$	3,246,361	$	655,108	$	974,279	$	720,041	$	896,933

(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 $2.4 million as of December 31, 2011 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 15 to the 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.

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(3)

Our long-term debt consists of the $291.8 million principal balance on the HollyFrontier 9.875% Senior Notes, the $150 million principal balance on the 6.875% Senior Notes, the $200 million principal balance on the 8.5% Senior Notes and a long-term financing obligation having a principal balance of $37.6 million at December 31, 2011.

(4)

Interest payments consist of interest on the HollyFrontier 9.875% Senior Notes, the 6.875% Senior Notes, the 8.5% 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 2012 and 2023 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 2016 and 2024.

(7)

HEP’s long-term debt consists of the $150 million and the $185 million principal balances on the 8.25% and 6.25% HEP Senior Notes and $200 million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement was amended on February 3, 2012 and expires in 2016.

(8)

Interest payments consist of interest on the 6.25% and 8.25% HEP Senior Notes and interest on long-term debt under the HEP Credit Agreement. Interest under the credit agreement debt is based on an effective interest rate of 3.49% at December 31, 2011.

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 to the Consolidated Financial Statements “Description of Business and Summary of Significant Accounting Policies.”

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, 2011, 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, 2011, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $378 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.

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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 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. Estimates of future discounted cash flows and fair values of assets 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, 2011, 2010 and 2009.

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. There were no impairments of intangible assets or goodwill during the years ended December 31, 2011, 2010 and 2009.

Variable Interest Entity

HEP is a VIE as defined under GAAP. A VIE is legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP’s economic performance. Additionally, since our obligation to absorb losses and receive benefits from HEP are significant to HEP, we are HEP’s primary beneficiary and therefore we consolidate HEP.

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.

New Accounting Pronouncements

Presentation of Comprehensive Income

In June 2011, an accounting standard update was issued that requires the presentation of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements and eliminates the option to present the components of other comprehensive income in the statement of stockholders’ equity. This standard is effective January 1, 2012 and will be applied retrospectively. This update will not have an impact on our financial condition, results of operations and cash flows.

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Intangibles — Goodwill and Other: Testing Goodwill for Impairment

In September 2011, an accounting standard update was issued that allows entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. This standard is effective for annual and interim goodwill impairment testing beginning January 1, 2012. This standard will not have an impact on our financial condition, results of operations and cash flows.

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 to mitigate price exposure with respect to:

•

our inventory positions;

•

natural gas purchases;

•

costs of crude oil;

•

prices of refined products; and

•

our refining margins.

Interest Rate Risk Management

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

As of December 31, 2011 HEP has an interest rate swap contract that hedges HEP’s exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million HEP Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin, currently 2.50%, which equaled an effective interest rate of 3.49% as of December 31, 2011. This swap matures in February 2016.

The following table presents balance sheet locations and related fair values of outstanding derivative instruments. These amounts are presented on a gross basis in accordance with GAAP disclosure requirements and do not reflect the netting of asset or liability positions permitted under the terms of master netting arrangements. Therefore, they are not equal to amounts presented in our consolidated balance sheets. Additionally, we held $30 million of cash on margin at December 31, 2011 to collateralize certain counterparty positions. These deposits have an offsetting current liability on our balance sheet and are not included in the amounts below.

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Derivative Instruments	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(Dollars in thousands)
December 31, 2011

*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	173,784	Accumulated other comprehensive income (unrealized gain)	$	173,338
				Cost of products sold (decrease)		446

			$173,784			$173,784

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	520	Accumulated other comprehensive income (unrealized loss)	$	520


*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	1,870	Cost of products sold (decrease)	$	1,870

Commodity price swap contracts	Accrued liabilities	$	1,252	Cost of products sold (increase)	$	1,252


December 31, 2010
*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	38	Accumulated other comprehensive loss (unrealized loss)	$	38

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss (unrealized loss)	$	10,026

*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	497	Cost of products sold (increase)	$	497

Publicly available 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 swap contracts. These counterparties are large financial institutions. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their commitments.

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, 2011 is presented below:


	Outstanding Principal		Estimated Fair Value		Estimated Change in Fair Value
	(In thousands)
HollyFrontier Senior Notes	$	641,797	$	693,979	$	26,300
HEP Senior Notes	$	335,000	$	344,350	$	8,600

For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2011, borrowings outstanding under the HEP Credit Agreement were $200 million. By means of its cash flow hedge, HEP has effectively converted the variable rate on $155 million of outstanding principal to a fixed rate of 3.49 %. For the unhedged $45 million portion, a hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.

At December 31, 2011, cash and cash equivalents included investments in investment grade, highly liquid investments with maturities of three months or less at the time of purchase and hence the interest rate market risk implicit in these cash 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.

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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 income from continuing operations 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 from continuing operations.


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Income from continuing operations	$	1,059,704		$	133,051		$	36,343
Subtract noncontrolling interest in income from continuing operations		(36,307	)		(29,087	)		(21,134	)
Add income tax provision		581,991			59,312			7,460
Add interest expense		78,323			74,196			40,346
Subtract interest income		(1,284	)		(1,168	)		(5,045	)
Add depreciation and amortization		159,707			117,529			98,751

EBITDA from continuing operations	$	1,842,134		$	353,833		$	156,721

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 an 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.

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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.

Reconciliations of refined product sales from produced products sold to total sales and other revenues


	Years Ended December 31,
	2011			2010			2009
	(Dollars in thousands, except per barrel amounts)
Average sales price per produced barrel sold	$	118.82		$	91.06		$	74.06
Times sales of produced refined products (BPD)		332,720			228,140			151,580
Times number of days in period		365			365			365

Refined product sales from produced products sold	$	14,429,833		$	7,582,666		$	4,097,495


Total refined product sales	$	14,429,833		$	7,582,666		$	4,097,495
Add refined product sales from purchased products and rounding ⁽¹⁾		350,843			130,866			106,893

Total refined products sales		14,780,676			7,713,532			4,204,388
Add direct sales of excess crude oil ⁽²⁾		558,855			459,743			453,958
Add other refining segment revenue ⁽³⁾		52,899			113,725			131,475

Total refining segment revenue		15,392,430			8,287,000			4,789,821
Add HEP segment sales and other revenues		213,566			182,114			146,561
Add corporate and other revenues		1,247			415			(636	)
Subtract consolidations and eliminations		(167,715	)		(146,600	)		(101,478	)

Sales and other revenues	$	15,439,528		$	8,322,929		$	4,834,268

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


	Years Ended December 31,
	2011			2010			2009
	(Dollars in thousands, except per barrel amounts)
Average cost of products per produced barrel sold	$	98.18		$	82.27		$	66.85
Times sales of produced refined products (BPD)		332,720			228,140			151,580
Times number of days in period		365			365			365

Cost of products for produced products sold	$	11,923,254		$	6,850,713		$	3,698,590


Total cost of products for produced products sold	$	11,923,254		$	6,850,713		$	3,698,590
Add refined product costs from purchased products sold and rounding ⁽¹⁾		351,788			131,668			114,566

Total cost of refined products sold		12,275,042			6,982,381			3,813,156
Add crude oil cost of direct sales of excess crude oil ⁽²⁾		550,619			454,566			449,488
Add other refining segment cost of products sold ⁽⁴⁾		18,672			73,410			75,229

Total refining segment cost of products sold		12,844,333			7,510,357			4,337,873
Subtract consolidations and eliminations		(164,255	)		(143,208	)		(99,865	)

Cost of products sold (exclusive of depreciation and amortization)	$	12,680,078		$	7,367,149		$	4,238,008

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


	Years Ended December 31,
	2011			2010			2009
	(Dollars in thousands, except per barrel amounts)
Average refinery operating expenses per produced barrel sold	$	5.36		$	5.08		$	5.24
Times sales of produced refined products (BPD)		332,720			228,140			151,580
Times number of days in period		365			365			365

Refinery operating expenses for produced products sold	$	650,933		$	423,017		$	289,912

Total refinery operating expenses per produced products sold	$	650,933		$	423,017		$	289,912
Add other refining segment operating expenses and rounding ⁽⁵⁾		35,659			26,573			23,408

Total refining segment operating expenses		686,592			449,590			313,320
Add HEP segment operating expenses		62,202			52,947			44,003
Add corporate and other costs		1,974			2,387			41
Subtract consolidations and eliminations		(2,687	)		(510	)		(509	)

Operating expenses (exclusive of depreciation and amortization)	$	748,081		$	504,414		$	356,855

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


	Years Ended December 31,
	2011			2010			2009
	(Dollars in thousands, except per barrel amounts)
Net operating margin per barrel	$	15.28		$	3.71		$	1.97
Add average refinery operating expenses per produced barrel		5.36			5.08			5.24

Refinery gross margin per barrel		20.64			8.79			7.21
Add average cost of products per produced barrel sold		98.18			82.27			66.85

Average sales price per produced barrel sold	$	118.82		$	91.06		$	74.06
Times sales of produced refined products (BPD)		332,720			228,140			151,580
Times number of days in period		365			365			365

Refined product sales from produced products sold	$	14,429,833		$	7,582,666		$	4,097,495

Total refined product sales from produced products sold	$	14,429,833		$	7,582,666		$	4,097,495
Add refined product sales from purchased products and rounding ⁽¹⁾		350,843			130,866			106,893

Total refined product sales		14,780,676			7,713,532			4,204,388
Add direct sales of excess crude oil ⁽²⁾		558,855			459,743			453,958
Add other refining segment revenue ⁽³⁾		52,899			113,725			131,475

Total refining segment revenue		15,392,430			8,287,000			4,789,821
Add HEP segment sales and other revenues		213,566			182,114			146,561
Add corporate and other revenues		1,247			415			(636	)
Subtract consolidations and eliminations		(167,715	)		(146,600	)		(101,478	)

Sales and other revenues	$	15,439,528		$	8,322,929		$	4,834,268

(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, 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.

-63-

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, 2011 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. Based on this assessment, management concludes that, as of December 31, 2011, 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, 2011. That report appears on page 65.

-64-

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, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, (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 effectiveness of 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, 2011, 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, 2011 and 2010, and the related consolidated statements of income, cash flows, equity and comprehensive income for each of the three years in the period ended December 31, 2011 and our report dated February 28, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 28, 2012

-65-

Index to Consolidated Financial Statements


	Page Reference
Report of Independent Registered Public Accounting Firm		67
Consolidated Balance Sheets at December 31, 2011 and 2010		68
Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009		69
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009		70
Consolidated Statements of Equity for the years ended December 31, 2011, 2010 and 2009		71
Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009		72
Notes to Consolidated Financial Statements		73

-66-

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, 2011 and 2010, and the related consolidated statements of income, cash flows, equity and comprehensive income for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 28, 2012

-67-

HOLLYFRONTIER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	December 31,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents (HEP: $3,269 and $403, respectively)	$	1,578,904		$	229,101
Marketable securities		211,639			1,343

Accounts receivable, net: Product and transportation (HEP: $34,071 and $22,508, respectively)		703,691			299,081
Crude oil resales		743,544			694,035

		1,447,235			993,116

Inventories: Crude oil and refined products		1,052,084			353,636

Materials and supplies (HEP: $1,483 and $202, respectively)		62,535			46,731

		1,114,619			400,367
Income taxes receivable		87,277			51,034

Prepayments and other (HEP: $1,161 and $573, respectively)		219,450			28,474

Total current assets		4,659,124			1,703,435

Properties, plants and equipment, at cost (HEP: $679,852 and $552,398, respectively)		3,631,787			2,215,828
Less accumulated depreciation (HEP: $(89,609) and $(60,300), respectively)		(578,882	)		(459,137	)

		3,052,905			1,756,691

Marketable securities (long-term)		50,067			—

Other assets: Turnaround costs		57,060			69,533
Goodwill (HEP: $288,991 and $81,602)		2,336,510			82,565
Intangibles and other (HEP: $75,902 and $72,434, respectively)		158,955			89,251

		2,552,525			241,349

Total assets	$	10,314,621		$	3,701,475


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $11,406 and $10,238, respectively)	$	2,243,072		$	1,317,446
Income taxes payable		40,366			—
Accrued liabilities (HEP: $16,285 and $21,206, respectively)		169,940			72,409
Deferred income tax liabilities		175,683			—

Total current liabilities		2,629,061			1,389,855

Long-term debt (HEP: $598,761 and $482,271, respectively)		1,214,742			810,561
Deferred income tax liabilities		463,721			131,935
Other long-term liabilities (HEP: $4,000 and $10,809, respectively)		171,197			80,985

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 and 152,692,864 shares issued as of December 31, 2011 and December 31, 2010, respectively		2,563			1,526
Additional capital		3,859,367			193,615
Retained earnings		1,964,656			1,206,328
Accumulated other comprehensive income (loss)		77,873			(26,246	)
Common stock held in treasury, at cost – 46,630,220 and 46,163,488 shares as of December 31, 2011 and 2010, respectively		(700,449	)		(677,804	)

Total HollyFrontier stockholders’ equity		5,204,010			697,419

Noncontrolling interest		631,890			590,720

Total equity		5,835,900			1,288,139

Total liabilities and equity	$	10,314,621		$	3,701,475

Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2011 and December 31, 2010. HEP is a consolidated variable interest entity.

Holly Corporation changed its name to HollyFrontier Corporation in connection with the consummation of its “merger of equals” with Frontier Oil Corporation which became effective on July 1, 2011. The financial statements included herein reflect financial information of the former Frontier business operations beginning July 1, 2011.

See accompanying notes.

-68-

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)


	Years Ended December 31,
	2011			2010			2009
Sales and other revenues	$	15,439,528		$	8,322,929		$	4,834,268

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		12,680,078			7,367,149			4,238,008
Operating expenses (exclusive of depreciation and amortization)		748,081			504,414			356,855
General and administrative expenses (exclusive of depreciation and amortization)		120,114			70,839			60,343
Depreciation and amortization		159,707			117,529			98,751

Total operating costs and expenses		13,707,980			8,059,931			4,753,957


Income from operations		1,731,548			262,998			80,311

Other income (expense):
Earnings of equity method investments		2,300			2,393			1,919
Interest income		1,284			1,168			5,045
Interest expense		(78,323	)		(74,196	)		(40,346	)
Merger transaction costs		(15,114	)		—			—
Acquisition costs – Tulsa refineries		—			—			(3,126	)

		(89,853	)		(70,635	)		(36,508	)

Income from continuing operations before income taxes		1,641,695			192,363			43,803

Income tax provision:
Current		590,851			35,472			(30,062	)
Deferred		(8,860	)		23,840			37,522

		581,991			59,312			7,460

Income from continuing operations		1,059,704			133,051			36,343

Discontinued operations
Income from discontinued operations, net of taxes		—			—			4,425
Gain on sale of discontinued operations, net of taxes		—			—			12,501

Income from discontinued operations		—			—			16,926


Net income		1,059,704			133,051			53,269

Less net income attributable to noncontrolling interest		36,307			29,087			33,736


Net income attributable to HollyFrontier stockholders	$	1,023,397		$	103,964		$	19,533


Earnings attributable to HollyFrontier stockholders:
Income from continuing operations	$	1,023,397		$	103,964		$	15,209
Income from discontinued operations		—			—			4,324

Net income	$	1,023,397		$	103,964		$	19,533


Earnings per share attributable to HollyFrontier stockholders – basic:
Income from continuing operations	$	6.46		$	0.98		$	0.15
Income from discontinued operations		—			—			0.05

Net income	$	6.46		$	0.98		$	0.20


Earnings per share attributable to HollyFrontier stockholders – diluted:

Income from continuing operations	$	6.42		$	0.97		$	0.15
Income from discontinued operations		—			—			0.05

Net income	$	6.42		$	0.97		$	0.20


Average number of common shares outstanding:
Basic		158,486			106,436			100,836
Diluted		159,294			107,218			101,206

See accompanying notes.

-69-

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Years Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income	$	1,059,704		$	133,051		$	53,269
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes discontinued operations)		159,707			117,529			99,633
Earnings of equity method investments, net of distributions		387			482			(419	)
Deferred income taxes		(8,860	)		23,840			37,522
Equity based compensation expense		26,825			11,498			7,549
Gain on sale of assets, before income taxes		—			—			(14,479	)
Change in fair value – derivative instruments		306			1,464			175
(Increase) decrease in current assets:
Accounts receivable		286,737			(228,466	)		(474,205	)
Inventories		(56,828	)		(96,854	)		(17,904	)
Income taxes receivable		(36,394	)		(14,990	)		(33,270	)
Prepayments and other		(14,214	)		369			(15,816	)
Increase (decrease) in current liabilities:
Accounts payable		(164,574	)		342,182			583,550
Income taxes payable		72,091			—			—
Accrued liabilities		60,467			22,414			1,651
Turnaround expenditures		(32,023	)		(34,966	)		(33,541	)
Other, net		(14,940	)		5,702			17,830

Net cash provided by operating activities		1,338,391			283,255			211,545

Cash flows from investing activities:
Additions to properties, plants and equipment		(334,904	)		(188,129	)		(269,552	)
Additions to properties, plants and equipment – HEP		(39,337	)		(25,103	)		(32,999	)
Acquisition of Tulsa Refinery facilities		—			—			(267,141	)
Acquisition of logistics assets from Sinclair Oil Company – HEP		—			—			(25,665	)
Increase in cash due to merger with Frontier		872,739			—			—
Investment in SLC Pipeline – HEP		—			—			(25,500	)
Investment in Sabine Biofuels		(9,125	)		—			—
Proceeds from sale of interest in Rio Grande Pipeline Company, net of transferred cash – HEP		—			—			31,865
Purchases of marketable securities		(561,899	)		—			(175,892	)
Sales and maturities of marketable securities		301,020			—			230,281

Net cash provided by (used for) investing activities		228,494			(213,232	)		(534,603	)

Cash flows from financing activities:
Borrowings under credit agreement		—			310,000			94,000
Repayments under credit agreement		—			(310,000	)		(94,000	)
Borrowings under credit agreement – HEP		118,000			66,000			239,000
Repayments under credit agreement – HEP		(77,000	)		(113,000	)		(233,000	)
Proceeds from Plains financing transaction		—			—			40,000
Repayments under Plains financing transaction		(1,160	)		(1,028	)		—
Proceeds from issuance of senior notes		—			—			287,925
Proceeds from issuance of senior notes – HEP					147,540			—
Proceeds from issuance of common units – HEP		75,815			—			133,035
Principal tender on senior notes		(8,203	)		—			—
Purchase of treasury stock		(42,795	)		(1,368	)		(1,214	)
Contribution from joint venture partner		33,500			23,500			15,150
Dividends		(252,133	)		(31,868	)		(30,123	)
Distributions to noncontrolling interest		(50,874	)		(48,493	)		(33,200	)
Excess tax benefit from equity based compensation		1,804			(1,094	)		(1,209	)
Purchase of units for restricted grants – HEP		(1,641	)		(2,704	)		(616	)
Deferred financing costs		(11,815	)		(3,121	)		(8,842	)
Issuance of common stock upon exercise of options		—			118			134
Other		(580	)		—			(191	)

Net cash provided by (used for) financing activities		(217,082	)		34,482			406,849

Cash and cash equivalents:

Increase for the period		1,349,803			104,505			83,791
Beginning of period		229,101			124,596			40,805

End of period	$	1,578,904		$	229,101		$	124,596


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	78,483		$	66,674		$	39,995
Income taxes	$	552,487		$	62,084		$	19,344

See accompanying notes.

-70-

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, 2008	$	735		$	121,298		$	1,145,388		$	(35,081	)	$	(690,800	)	$	394,792		$	936,332
Net income		—			—			19,533			—			—			33,736			53,269
Dividends		—			—			(30,580	)		—			—			—			(30,580	)
Distributions to noncontrolling interest holders		—			—			—			—			—			(33,200	)		(33,200	)
Elimination of noncontrolling interest upon HEP’s sale of Rio Grande Pipeline Company		—			—			—			—			—			(8,718	)		(8,718	)
Other comprehensive income, net of tax		—			—			—			9,381			—			2,021			11,402
Issuance of common shares		28			73,972			—			—			—			—			74,000
Issuance of HEP common units, net of issuing costs		—			—			—			—			—			186,801			186,801
Contribution from joint venture partner		—			—			—			—			—			13,650			13,650
Issuance of common stock upon exercise of stock options		1			134			—			—			—			—			135
Tax benefit from stock options		—			371			—			—			—			—			371
Issuance of common stock under incentive compensation plans, net of forfeitures		—			(6,083	)		—			—			6,083			—			—
Equity based compensation, net of tax benefit		—			5,873			—			—			—			699			6,572
Two-for-one stock split		763			(763	)		—			—			—			—			—
Purchase of treasury stock		—			—			—			—			(1,214	)		—			(1,214	)
Other		—			—			—			—			—			(1,039	)		(1,039	)


Balance at December 31, 2009	$	1,527		$	194,802		$	1,134,341		$	(25,700	)	$	(685,931	)	$	588,742		$	1,207,781
Net income		—			—			103,964			—			—			29,087			133,051
Dividends		—			—			(31,977	)		—			—			—			(31,977	)
Distributions to noncontrolling interest holders		—			—			—			—			—			(48,493	)		(48,493	)
Other comprehensive loss, net of tax		—			—			—			(546	)		—			(1,623	)		(2,169	)
Contribution from joint venture partner		—			—			—			—			—			23,500			23,500
Issuance of common stock upon exercise of stock options		—			118			—			—			—			—			118
Tax benefit from stock options		—			416			—			—			—			—			416
Issuance of common stock under incentive compensation plans, net of forfeitures		(1	)		(9,494	)		—			—			9,495			—			—
Equity based compensation, net of tax benefit		—			7,773			—			—			—			2,215			9,988
Purchase of treasury stock		—			—			—			—			(1,368	)		—			(1,368	)
Other		—			—			—			—			—			(2,708	)		(2,708	)


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	)
Distributions 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

See accompanying notes.

-71-

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)


	Years Ended December 31,
	2011			2010			2009
Net income	$	1,059,704		$	133,051		$	53,269

Other comprehensive income (loss):

Securities available-for-sale:
Unrealized gain (loss) on available-for-sale securities		(530	)		114			173
Reclassification adjustment to net income on sale or maturity of marketable securities		14			—			236

Total unrealized gain (loss) on available-for-sale securities		(516	)		114			409


Hedging instruments:
Change in fair value of cash flow hedging instruments		176,895			(1,999	)		3,726
Amortization of unrealized loss attributable to discontinued cash flow hedge		41			—			—
Reclassification adjustment to net income on settlement of cash flow hedging instruments		—			1,076			—

Total unrealized gain (loss) on hedging instruments		176,936			(923	)		3,726


Retirement medical obligation adjustment		(3,515	)		(238	)		742
Minimum pension liability adjustment		(71	)		(1,470	)		12,497


Other comprehensive income (loss) before income taxes		172,834			(2,517	)		17,374

Income tax expense (benefit)		66,138			(348	)		5,972


Other comprehensive income (loss)		106,696			(2,169	)		11,402


Total comprehensive income		1,166,400			130,882			64,671

Less noncontrolling interest in comprehensive income		39,122			27,464			35,757


Comprehensive income attributable to HollyFrontier stockholders	$	1,127,278		$	103,418		$	28,914

See accompanying notes.

-72-

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 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”) effective 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 five petroleum refineries that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. As of December 31, 2011, 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 Ethanol Management Company (“EMC”), a products terminal and blending facility near Denver, Colorado and a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur, Texas; and

•

owned a 42% 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 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

On August 3, 2011, our Board of Directors declared a two-for-one stock split, payable in the form of a common stock dividend for each issued and outstanding share of our common stock. The stock dividend was paid August 31, 2011 to all shareholders of record on August 24, 2011. We have retained the current par value of $0.01 per share for all shares of our common stock and have reclassified $763,000 (the amount equal to the par value of the additional stock issued) from additional capital to common stock to reflect this stock split at December 31, 2010. All references to share and per share amounts in these consolidated financial statements and related disclosures have been adjusted to reflect the effect of the stock split for all periods presented.

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Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we control through a 50% or more ownership interest or through a controlling financial interest with respect to variable interest entities. All significant intercompany transactions and balances have been eliminated.

Variable Interest Entity: 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 or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP’s economic performance. Additionally, since our obligation to absorb losses and receive benefits from HEP are significant to HEP, we are HEP’s primary beneficiary and therefore, we consolidate HEP. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for HEP may not agree to amounts reported in HEP’s periodic public filings.

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 are primarily issued by government and municipal entities with the maximum maturity or put date of any individual issue 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.

Accounts Receivable: The majority of our accounts receivable are due from companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, is required. We reserve for doubtful accounts based on current sales levels as well as specific accounts identified as high risk, which historically have been minimal. Credit losses are charged to the allowance for doubtful accounts when an account is deemed uncollectible. Our allowance for doubtful accounts was $3.5 million and $2.1 million at December 31, 2011 and 2010, 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.

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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 14, Derivative Instruments and Hedging Activities, 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. No impairments of long-lived assets were recorded during the years ended December 31, 2011, 2010 and 2009.

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.

At December 31, 2011, we have an asset retirement obligations of $14.4 million, which are included in “Other long-term liabilities” in our consolidated balance sheets. We acquired asset retirement obligations of $6.2 million in connection with our “merger of equals” with Frontier on July 1, 2011 and $5.8 million with our Tulsa refinery facility acquisitions in 2009 (see Note 2). Accretion expense was insignificant for the years ended December 31, 2011, 2010 and 2009.

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.

In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates minimum annual cash inflows of $23.4 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 million. At December 31, 2011, the balance of this transportation agreement was $46.5 million, net of accumulated amortization of $13.7 million, which is included in “Intangibles and other” in our consolidated balance sheets. There were no impairments of intangible assets or goodwill during the years ended December 31, 2011, 2010 and 2009.

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, 2011, HEP’s underlying equity in the SLC Pipeline was $60.9 million compared to its recorded investment balance of $25.3 million, a difference of $35.6 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.

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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.

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.

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, timeframe 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.

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.

New Accounting Pronouncements

Presentation of Comprehensive Income

In June 2011, an accounting standard update was issued that requires the presentation of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements and eliminates the option to present the components of other comprehensive income in the statement of stockholders’ equity. This standard is effective January 1, 2012 and will be applied retrospectively. This standard will not have an impact on our financial condition, results of operations and cash flows.

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Intangibles — Goodwill and Other: Testing Goodwill for Impairment

NOTE 2: Merger and Acquisitions

Holly—Frontier Merger

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier for purposes of creating a more diversified company having a broader geographic sales footprint, stronger financial position and to create a more efficient corporate overhead structure, while also realizing synergies and promoting accretion to earnings per share. The legacy Frontier business operations consist of crude oil refining and the wholesale marketing of refined petroleum products produced at the El Dorado and Cheyenne Refineries and serve markets in the Rocky Mountain and Plains States regions of the United States. 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. Concurrent with the merger, we changed our name to HollyFrontier Corporation and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Subsequent to the merger and following approval by the post-closing board of directors of HollyFrontier, Frontier merged with and into HollyFrontier, with HollyFrontier continuing as the surviving corporation.

In accordance with the merger agreement, we issued 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 stock in connection with the merger was $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. The number of shares issued in connection with our merger with Frontier and the closing market price of our common stock at July 1, 2011 have been adjusted to reflect the two-for-one stock split on August 31, 2011.

The merger has been accounted for using the acquisition method of accounting with Holly being considered the acquirer of Frontier for accounting purposes. Therefore, the purchase price was allocated to the fair value of the acquired assets and assumed liabilities at the acquisition date, with the excess purchase price being recorded as goodwill. The goodwill resulting from the merger is primarily due to the favorable location of the acquired refining facilities and the expected synergies to be gained from our combined business operations. Goodwill related to this merger is not deductible for income tax purposes.

The following table summarizes our fair value estimates of the Frontier assets and liabilities recognized upon our merger on July 1, 2011:


	(in millions)
Cash and cash equivalents	$	872.7
Accounts receivable		737.9
Inventories		657.4
Properties, plants and equipment		1,054.3
Goodwill		2,254.0
Income taxes receivable		37.8
Other assets		32.8
Accounts payable		(1,076.7	)
Accrued liabilities		(40.7	)
Long-term debt		(370.6	)
Other long-term liabilities		(96.1	)
Deferred income taxes		(357.6	)

Net tangible and intangible assets acquired and liabilities assumed	$	3,705.2

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Our valuations of the acquired Frontier assets and liabilities are not final as of December 31, 2011. These fair value estimates, including the value of goodwill and the allocation thereof to our reporting units, are preliminary in nature and therefore, may change upon the completion of cash valuations.

Beginning July 1, 2011, HollyFrontier’s consolidated financial and operating results reflect the operations of the merged Frontier businesses. Our consolidated statements of income include revenues and income before income taxes of $4,183.8 million and $575.8 million, respectively, for the period from July 1, 2011 through December 31, 2011 that are attributable to the operations of the legacy Frontier refineries.

Assuming the merger had been consummated on January 1, 2010, pro forma revenues, net income and basic and diluted earnings per share are as follows:


	Years Ended December 31,
	2011		2010
	(In thousands)
	(Unaudited)
Sales and other revenues	$	19,418,709	$	14,207,835
Net income attributable to HollyFrontier stockholders	$	1,335,257	$	179,979
Basic earnings per share	$	6.37	$	0.86
Diluted earnings per share	$	6.35	$	0.86

The pro forma financial information above reflects our fair value estimates of the acquired Frontier assets and liabilities. Adjustments made to derive pro forma net income primarily relate to depreciation and amortization expense in order to reflect our new basis in the acquired legacy Frontier refining facilities.

As of December 31, 2011, we have recognized $15.1 million in merger transaction costs that are presented separately in our income statements and primarily relate to legal, advisory and other professional fees incurred since the announcement of our merger agreement in February 2011. This does not include costs to integrate the operations of the combined company. For the year ended December 31, 2011, general and administrative expenses include $26.5 million in integration and severance costs associated with the merger integration.

Tulsa Refinery Acquisitions

On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa West facility”) from Sunoco for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. In October 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities that were acquired as part of the refinery assets. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing transaction (see Note 13).

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, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. We operate the Tulsa Refineries in an integrated manner, with both complexes having a combined crude processing rate of 125,000 BPSD.

In accounting for the Tulsa acquisitions, we recorded $20.6 million in materials and supplies, $139.2 million in crude oil and refined products inventory, $203.8 million in properties, plants and equipment, $8.2 million in prepayments and other, $6.3 million in accrued liabilities and $24.4 million in other long-term liabilities. The acquired liabilities primarily relate to environmental and asset retirement obligations. Additionally, we incurred $3.1 million in costs directly related to these acquisitions that were expensed as acquisition costs in 2009.

NOTE 3: 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 USA, Inc.’s (“Alon”) refinery in Big Spring, Texas.

As of December 31, 2011, we owned a 42% interest in HEP, including the 2% general partner interest. We are the primary beneficiary of HEP’s earnings and cash flows and therefore we consolidate HEP. See Note 22 for supplemental guarantor/non-guarantor financial information, including HEP balances included in these consolidated financial statements. All intercompany transactions with HEP are eliminated in our consolidated financial statements.

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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 represented 78% of HEP’s total revenues for the year ended December 31, 2011. We do not provide financial or equity support through any liquidity arrangements and /or 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 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 13 for a description of HEP’s debt obligations.

At December 31, 2011, we have an agreement to pledge up to 6,000,000 of our HEP common units to collateralize certain crude oil purchases. These units represent a 21% ownership interest in HEP.

HEP has risk associated with its operations. If a major shipper of HEP were to terminate its contracts or fail to meet desired shipping or throughput levels for an extended period 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.

2011 Acquisition

Legacy Frontier Tankage and Terminal Asset Transaction

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

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

2009 Acquisitions

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. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million.

Roadrunner / Beeson Pipelines Transaction

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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

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 its 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. The SLC Pipeline commenced operations effective March 2009 and allows various refineries in the Salt Lake City area, including our Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. HEP’s capitalized joint venture contribution was $25.5 million.

Rio Grande Pipeline Sale

In accounting for this sale, HEP recorded a gain of $14.5 million and a receivable of $2.2 million representing its final distribution from Rio Grande. The recorded net asset balance of Rio Grande at December 1, 2009, was $22.7 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.

The following table provides income statement information related to HEP’s discontinued operations:


	Year Ended December 31, 2009
	(In thousands)
Income from discontinued operations before income taxes	$	5,367
Income tax expense		(942	)

Income from discontinued operations, net		4,425
Gain on sale of discontinued operations before income taxes		14,479
Income tax expense		(1,978	)

Gain on sale of discontinued operations, net		12,501

Income from discontinued operations, net	$	16,926

Transportation Agreements

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HEP Common Unit Issuances

2011 Issuances

As a result of these 2011 HEP common unit issuances, 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. Additionally, we recorded a reduction of $80.7 million to additional capital that relates to a deferred tax liability that was recorded as a result of the goodwill transferred to HEP upon its acquisition of our tankage and terminal assets in November 2011.

2009 Issuances

In December 2009, HEP issued 1,373,609 of its common units having a value of $53.5 million to Sinclair as partial consideration of its purchase of Sinclair’s Tulsa logistics assets.

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 due to the short-term maturity of these instruments. Debt consists of outstanding principal under HEP’s revolving credit agreement (which approximates fair value as interest rates are reset frequently at current interest rates) and senior notes.

Fair value measurements are derived using inputs, (assumptions that market participants would use in pricing an asset or liability, including assumptions about risk). GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

•

(Level 1) Quoted prices in active markets for identical assets or liabilities.

•

(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

•

(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

The carrying amounts and related estimated fair values of our investments in marketable securities, derivative instruments and the senior notes at December 31, 2011 and December 31, 2010 are as follows:

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			December 31, 2011						December 31, 2010
Financial Instrument	Fair Value Input Level		Carrying Amount			Fair Value			Carrying Amount			Fair Value
			(In thousands)
Investments in marketable securities:
Equity securities		Level 1	$	753		$	753		$	1,343		$	1,343
Marketable debt securities		Level 2	$	260,953		$	260,953		$	—		$	—

Derivative instruments:
NYMEX futures contracts		Level 1	$	(1,252	)	$	(1,252	)	$	—		$	—
Commodity price swaps		Level 2	$	144,038		$	144,038		$	(535	)	$	(535	)
Commodity price swaps		Level 3	$	31,616		$	31,616		$	—		$	—
HEP interest rate swap		Level 2	$	(520	)	$	(520	)	$	(10,026	)	$	(10,026	)

Senior notes:
HollyFrontier senior notes		Level 2	$	651,262		$	693,979		$	289,509		$	327,000
HEP senior notes		Level 2	$	325,860		$	344,350		$	323,271		$	339,900

Level 1 Financial Instruments

Our investments in equity securities and 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 debt securities and derivative instruments consisting of commodity price swaps and HEP’s interest rate swap are measured and recorded at fair value using Level 2 inputs. With respect to the commodity price and interest rate swap contracts, fair value is 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 swap.

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

Level 3 Financial Instruments

During 2011, we entered into certain commodity price swap contracts related to forecasted sales of 14,640,000 barrels of diesel and unleaded gasoline for which quoted forward market prices are not readily available. The forward rate used to value these price swaps was derived using a projected forward rate using quoted market rates for similar products, adjusted for regional pricing differentials, a Level 3 input. At December 31, 2011, we had a pre-tax unrealized gain in accumulated other comprehensive income related to these contracts. Our Level 3 commodity price swaps had no effect on earnings during the year ended December 31, 2011.

NOTE 5: Earnings Per Share

Basic earnings per share from continuing operations is calculated as income from continuing operations 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 stock options, variable restricted shares and variable performance shares. The average number of shares of common stock and per share amounts have been adjusted to reflect the two-for-one stock split effective August 31, 2011. The following is a reconciliation of the denominators of the basic and diluted per share computations for income from continuing operations:


	Years Ended December 31,
	2011		2010		2009
	(In thousands, except per share data)
Earnings attributable to HollyFrontier stockholders:
Income from continuing operations	$	1,023,397	$	103,964	$	15,209

Average number of shares of common stock outstanding		158,486		106,436		100,836
Effect of dilutive stock options, variable restricted shares and performance share units		808		782		370

Average number of shares of common stock outstanding assuming dilution		159,294		107,218		101,206

Basic earnings per share from continuing operations	$	6.46	$	0.98	$	0.15

Diluted earnings per share from continuing operations	$	6.42	$	0.97	$	0.15

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NOTE 6: Stock-Based Compensation

As of December 31, 2011, we have two principal share-based compensation plans including the Frontier plan that was retained upon the July 1, 2011 merger (the “Long-Term Incentive Compensation Plan”). All outstanding and unvested restricted stock and performance share grants under the legacy Frontier plan were converted into equivalent HollyFrontier units based on the July 1, 2011 common stock conversion ratio of 0.4811. A portion of the fair value of these awards (based on our July 1, 2011 closing stock price of $35.93) relative to the remaining vesting period of the awards will be expensed over the remaining terms of these grants.

The compensation cost charged against income for these plans was $24.7 million, $9.3 million and $6.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. The total income tax benefit recognized in the statements of income for share-based compensation arrangements was $9.6 million, $3.6 million and $2.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. Our current accounting policy for recognizing compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs ratably over the vesting periods. At December 31, 2011, 8,430,045 shares of common stock were reserved for future grants under the current Long-Term Incentive Compensation Plan, which allows for awards of common stock, options, restricted stock, or other performance awards.

Additionally, HEP maintains share-based compensation plans for HEP directors and select Holly Logistic Services, L.L.C. executives and employees. Compensation cost attributable to HEP’s share-based compensation plans for the years ended December 31, 2011, 2010 and 2009 was $2.1 million, $2.2 million and $1.2 million, respectively.

Restricted Stock

Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and non-employee directors restricted stock awards with substantially all awards vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients generally have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain performance targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, 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 activity and changes during the year ended December 31, 2011 is presented below:


Restricted Stock	Grants			Weighted- Average Grant Date Fair Value		Aggregate Intrinsic Value ($000)
Outstanding at January 1, 2011 (non-vested)		693,992		$	14.65
Granted ⁽¹⁾		983,858			28.61
Vesting and transfer of ownership to recipients		(528,566	)		17.05
Forfeited		(26,934	)		26.08

Outstanding at December 31, 2011 (non-vested)		1,122,350		$	25.48	$	26,263

(1)	Includes 425,554 non-vested restricted stock grants under the legacy Frontier plan that were outstanding and retained by HollyFrontier at July 1, 2011.

The total fair value of restricted stock vested and transferred to recipients during the years ended December 31, 2011, 2010 and 2009 was $9.1 million, $4.2 million and $3.4 million, respectively. As of December 31, 2011, there was $13.9 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.2 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 one to three years. Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or “market performance” criteria.

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During the year ended December 31, 2011, we granted 354,660 performance share units having a fair value based on our grant date closing stock price of $28.79. These units are payable in stock and are subject to certain financial performance criteria. The fair value of these performance share unit awards is based on 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, 2011, estimated share payouts for outstanding non-vested performance share unit awards ranged from 150% to 195%.

For the legacy Frontier performance share units assumed at July 1, 2011, performance is based on market performance criteria, which 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 payable in stock based on share price performance relative to the defined peer group and can range from zero to 125% of the initial target award. These performance share units were valued at July 1, 2011 using a Monte Carlo valuation model, which simulates future stock price movements using key inputs including grant date and measurement date stock prices, expected stock price performance, expected rate of return and volatility of our stock price relative to the peer group over the three-year performance period. The fair value of these performance share units at July 1, 2011 was $8.6 million. Of this amount, $7.3 million relates to post-merger services and will be recognized ratably over the remaining service period through 2013.

A summary of performance share unit activity and changes during the year ended December 31, 2011 is presented below:


Performance Share Units	Grants
Outstanding at January 1, 2011 (non-vested)		556,186
Granted ⁽¹⁾		354,660
Vesting and transfer of ownership to recipients		(136,058	)

Outstanding at December 31, 2011 (non-vested)		774,788

(1)	Includes 225,116 non-vested performance share grants under the legacy Frontier plan that were outstanding and retained by HollyFrontier at July 1, 2011.

For the year ended December 31, 2011 we issued 178,148 shares of our common stock having a fair value of $2.6 million related to vested performance share units. Based on the weighted average grant date fair value of $20.71 there was $11.7 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 1.1 years.

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

Our investment portfolio at December 31, 2011 consisted of cash, cash equivalents and investments in debt securities primarily issued by government and municipal entities. We also hold 1,000,000 shares of Connacher Oil and Gas Limited common stock that was received as partial consideration upon the sale of our Montana refinery in 2006.

We invest in highly-rated marketable debt securities, primarily issued by government and municipal entities that have maturities at the date of purchase of greater than three months. We also invest in other marketable debt securities with the maximum maturity or put date of any individual issue generally not greater than two years from the date of purchase. All of these instruments, including investments in equity securities, 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, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

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The following is a summary of our available-for-sale securities:


	Available-for-Sale Securities
	Amortized Cost		Gross Unrealized Gain (Loss)		Estimated Fair Value (Net Carrying Amount)
	(In thousands)
December 31, 2011
Marketable debt securities (state and political subdivisions)	$	260,879	$	74	$	260,953
Equity securities		610		143		753

Total marketable securities	$	261,489	$	217	$	261,706

December 31, 2010
Equity securities	$	610	$	733	$	1,343

NOTE 8: Inventories

Inventory consists of the following components:


	December 31,
	2011		2010
	(In thousands)
Crude oil	$	400,952	$	96,570
Other raw materials and unfinished products ⁽¹⁾		137,356		68,792
Finished products ⁽²⁾		513,776		188,274
Process chemicals ⁽³⁾		1,180		22,512
Repairs and maintenance supplies and other		61,355		24,219

Total inventory	$	1,114,619	$	400,367

(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 $378 million and $284 million at December 31, 2011 and 2010, respectively. For the years ended December 31, 2011 and 2010, we recognized reductions of $0.1 million and $4.1 million, respectively, to cost of products sold as we liquidated certain LIFO inventory quantities carried at historical LIFO acquisition costs below market value at the time of liquidation.

NOTE 9: Properties, Plants and Equipment


	December 31,
	2011			2010
	(In thousands)
Land, buildings and improvements	$	168,108		$	91,169
Refining facilities		2,106,900			1,174,980
Pipelines and terminals		922,866			539,045
Transportation vehicles		29,418			20,972
Other fixed assets		97,676			83,199
Construction in progress		306,819			306,463

		3,631,787			2,215,828
Accumulated depreciation		(578,882	)		(459,137	)

	$	3,052,905		$	1,756,691

We capitalized interest attributable to construction projects of $17.2 million and $7.2 million for the years ended December 31, 2011 and 2010, respectively.

Depreciation expense was $125 million, $94 million and $78.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. Depreciation expense for the years ended December 31, 2011, 2010 and 2009 includes $29.5 million, $27 million and $25 million, respectively, of depreciation expense attributable to the operations of HEP.

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NOTE 10: Goodwill

The following is a summary of changes by segment to the carrying amounts of goodwill for the year ended December 31, 2011:


	Refining Segment		HEP		Total
	(In thousands)

Balance at January 1, 2011	$	963	$	81,602	$	82,565
Goodwill attributable to merger with Frontier		2,046,556		207,389		2,253,945

Balance at December 31, 2011	$	2,047,519	$	288,991	$	2,336,510

Based on our annual impairment assessments, we determined that the fair value of our reporting units exceeded their respective carrying values and therefore no impairments have been recognized. As of December 31, 2011, there have been no impairments to our goodwill balances.

NOTE 11: UNEV Pipeline Joint Venture

We own a 75% joint venture interest in the recently completed UNEV Pipeline, a 400 mile 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal and ethanol blending facilities in the Cedar City, Utah and North Las Vegas areas and storage facilities at the Cedar City terminal with Sinclair, our joint venture partner, owning the remaining 25% interest. The pipeline has a capacity of 62,000 BPD (based on gasoline equivalents), and has the capacity for further expansion to 120,000 BPD. The cost of constructing this pipeline including terminals and ethanol blending and storage facilities was approximately $410 million, which is included under “Properties, plants and equipment” in our consolidated balance sheets. The pipeline was mechanically complete in November 2011 and initial start-up activities commenced in December 2011. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

NOTE 12: Environmental Costs

Consistent with our accounting policy for environmental remediation costs, we expensed $14 million, ($0.6) million and $4.2 million for the years ended December 31, 2011, 2010 and 2009, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $42.2 million and $26.2 million at December 31, 2011 and 2010, respectively, of which $31.7 million and $20.4 million, respectively, was classified as other long-term liabilities. These amounts include $7.3 million in environmental liabilities that we assumed in connection with our merger with Frontier in July 2011. Future expenditures for environmental remediation that are expected to be incurred over the next several years are not discounted to their present value.

NOTE 13: Debt

HollyFrontier Credit Agreement

We were in compliance with all covenants at December 31, 2011. At December 31, 2011, we had no outstanding borrowings and outstanding letters of credit totaling $6.1 million under the HollyFrontier Credit Agreement. At that level of usage, the unused commitment was $993.9 million at December 31, 2011.

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HEP Credit Agreement

At December 31, 2011, HEP had a $275 million senior secured revolving credit facility expiring in February 2016 (the “HEP Credit Agreement”) with an outstanding balance of $200 million. On February 3, 2012, the HEP Credit Agreement was amended, increasing the size of the credit facility from $275 million to $375 million (the “HEP Amended 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 and to fund distributions to unitholders up to a $30 million sub-limit. The HEP Amended Credit Agreement expires in February 2016; however, in the event that the 6.25% HEP senior notes (discussed later) are not repurchased, defeased, refinanced, extended or repaid prior to September 1, 2014, the HEP Amended Credit Agreement will expire on that date.

HEP’s obligations under the HEP Amended Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our consolidated balance sheets). Indebtedness under the HEP Amended Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and 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 other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

HollyFrontier Senior Notes

Our senior notes consist of the following:

•

9.875% Senior Notes ($291.8 million principal amount maturing June 2017)

•

6.875% Senior Notes ($150 million principal amount maturing November 2018)⁽¹⁾

•

8.5% Senior Notes ($200 million principal amount maturing September 2016)⁽¹⁾

(1)	Represent senior notes assumed upon our July 1, 2011 merger with Frontier.

In June 2009, we issued $200 million in aggregate principal amount of the 9.875% Senior Notes maturing June 15, 2017. A portion of the $187.9 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa West facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the 9.875% Senior Notes that was used to fund the cash portion of our acquisition of the Tulsa East facility.

HollyFrontier Financing Obligation

In October 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa West facility as well as certain crude oil pipeline receiving facilities to an affiliate of Plains for $40 million in cash. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits with Plains for crude oil purchased by them and delivered to our Tulsa West facility for storage. Due to our continuing involvement in these assets, this sale and lease transaction has been accounted for as a financing obligation. As a result, we retained these assets on our books and recorded a liability representing the $40 million in proceeds received.

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HEP Senior Notes

HEP’s senior notes consist of the following:

•

6.25% HEP Senior Notes ($185 million principal amount maturing March 2015)

•

8.25% HEP Senior Notes ($150 million principal amount maturing March 2018)

HEP also has $185 million in aggregate principal amount of 6.25% HEP Senior Notes maturing March 1, 2015 that are registered with the SEC.

Consolidated Debt

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


	December 31, 2011			December 31, 2010
	(In thousands)
9.875% Senior Notes
Principal	$	291,812		$	300,000
Unamortized discount		(8,930	)		(10,491	)

		282,882			289,509

6.875% Senior Notes
Principal		150,000			—
Unamortized premium		6,490			—

		156,490			—

8.5% Senior Notes
Principal		199,985			—
Unamortized premium		11,905			—

		211,890			—

Financing obligation
Principal		37,620			38,781

Total HollyFrontier long-term debt		688,882			328,290

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	December 31, 2011			December 31, 2010
	(In thousands)
HEP Credit Agreement		200,000			159,000

HEP 6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(8,331	)		(10,961	)
Unamortized premium – dedesignated fair value hedge		1,098			1,444

		177,767			175,483
HEP 8.25% Senior Notes
Principal		150,000			150,000
Unamortized discount		(1,907	)		(2,212	)

		148,093			147,788

Total HEP long-term debt		525,860			482,271


Total long-term debt	$	1,214,742		$	810,561

Principal maturities of long-term debt are as follows:


Years Ending December 31,	(In thousands)
2012	$	1,309
2013		1,477
2014		201,666
2015		186,880
2016		202,106
Thereafter		620,979

Total	$	1,214,417

NOTE 14: Derivative Instruments and Hedging Activities

Commodity Price Risk Management

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.

As of December 31, 2011, we have outstanding swap contracts serving as cash flow hedges against price risk on forecasted 2012 purchases of 14,640,000 barrels of WTI crude oil and forecasted sales of 7,320,000 barrels of ultra-low sulfur diesel and 7,320,000 barrels of conventional unleaded gasoline. In the aggregate, these cash flow hedges effectively hedge our gross margin on forecasted gasoline and diesel sales, totaling 40,000 BPD in 2012. 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 in the income statement as the hedging instruments mature. Also on a quarterly basis, hedge effectiveness 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 ineffectiveness is recorded to cost of products sold. To date, ineffectiveness on these cash flow hedges have been insignificant.

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We also have swap contracts that lock in the spread between gasoline and butane on forecasted sales (112,500 barrels of gasoline through January 2012) and NYMEX futures contracts to lock in prices on forecasted sales and purchases of inventory (292,000 barrels and 411,000 barrels, respectively, through 2013). These contracts are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to cost of products sold.

Interest Rate Risk Management

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

As of December 31, 2011 HEP has an interest rate swap contract that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million credit agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin, currently 2.50%, which equaled an effective interest rate of 3.49% as of December 31, 2011. This swap matures in February 2016. HEP has designated this interest rate swap as a cash flow hedge. To date, ineffectiveness on this cash flow hedge has been insignificant.

Prior to entering into the swap contract in December 2011 (discussed above), HEP terminated its previous interest rate swap that prior to settlement also served to hedge HEP’s exposure to the effects of LIBOR changes on the same $155 million credit agreement advance. HEP terminated this swap at a cost of $6 million, to lock in a lower effective interest rate on this $155 million advance, which by means of the previous swap contract was effectively fixed at 6.24% at the time of termination.

At December 31, 2011, HEP had a pre-tax accumulated other comprehensive loss of $6.5 million that relates to its current and previous cash flow hedging instruments. Of this amount, $6 million relates to the cash flow hedge terminated in December 2011 and represents the application of hedge accounting prior to termination. This amount will be amortized as a charge to interest expense through February 2013, the remaining term of the terminated swap contract.


Derivative Instruments	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(In thousands)
December 31, 2011

Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts	Prepayments and other current assets	$	173,784	Accumulated other comprehensive income (unrealized gain)	$	173,338
				Cost of products sold (decrease)		446

		$	173,784		$	173,784

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	520	Accumulated other comprehensive income (unrealized loss)	$	520


*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	1,870	Cost of products sold (decrease)	$	1,870

Commodity price swap contracts	Accrued liabilities	$	1,252	Cost of products sold (increase)	$	1,252

*December 31, 2010*

*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	38	Accumulated other comprehensive loss (unrealized loss)	$	38

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss (unrealized loss)	$	10,026


*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	497	Cost of products sold (increase)	$	497

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At December 31, 2011, there was a pre-tax net unrealized gain of $172.8 million classified in accumulated other comprehensive income that relates to our commodity cash flow hedges and HEP’s cash flow hedge of interest. Assuming commodity prices and interest rates remain unchanged, an unrealized gain of approximately $173 million will be effectively transferred from accumulated other comprehensive income into the income statement as the hedging instruments mature over the next twelve-month period.

For the year ended December 31, 2011, maturities and fair value adjustments attributable to our economic hedges resulted in decreases of $3.2 million to cost of products sold. For the year ended December 31, 2010, we recognized a $1.3 million charge to cost of products sold and a $0.4 million charge to operating expenses that are attributable to losses resulting from fair value changes to our commodity price swap contracts.

HEP previously had interest rate swap contracts that served as economic hedges on interest attributable to outstanding debt. For the years ended December 31, 2010 and 2009, HEP recognized $1.5 million and $0.2 million, respectively, in non-cash charges to interest expense as a result of fair value changes to these swap contracts.

NOTE 15: Income Taxes

The provision for income taxes is comprised of the following:


	Years Ended December 31,
	2011			2010		2009
	(In thousands)
Current
Federal	$	499,535		$	30,999	$	(24,876	)
State		91,316			4,473		(2,266	)
Deferred
Federal		(9,679	)		21,796		33,269
State		819			2,044		4,253

	$	581,991		$	59,312	$	10,380

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


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Tax computed at statutory rate	$	574,682		$	67,327		$	15,331
State income taxes, net of federal tax benefit		64,284			4,372			1,708
Domestic production activities deduction		(32,194	)		(940	)		—
Tax exempt interest		—			—			(168	)
Discontinued operations (including noncontrolling interest)		—			—			7,720
Noncontrolling interest in continuing operations		(14,221	)		(11,315	)		(13,123	)
Tax settlement		(12,125	)		—			—
Other		1,565			(132	)		(1,088	)

	$	581,991		$	59,312		$	10,380

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, 2011 and 2010 are as follows:

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	December 31, 2011
	Assets		Liabilities			Total
	(In thousands)
Deferred taxes
Accrued employee benefits	$	22,791	$	—		$	22,791
Accrued postretirement benefits		4,012		—			4,012
Accrued environmental costs		2,253		—			2,253
Inventory differences		—		(161,428	)		(161,428	)
Deferred turnaround costs		—		(356	)		(356	)
Prepayments and other		37,442		(80,397	)		(42,955	)

Total current		66,498		(242,181	)		(175,683	)
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(511,788	)		(511,788	)
Accrued postretirement benefits		41,873		—			41,873
Accrued environmental costs		4,651		—			4,651
Deferred turnaround costs		—		(22,971	)		(22,971	)
Investment in HEP		—		(13,389	)		(13,389	)
Other		42,618		(4,715	)		37,903

Total noncurrent		89,142		(552,863	)		(463,721	)

Total	$	155,640	$	(795,044	)	$	(639,404	)


	December 31, 2010
	Assets		Liabilities			Total
	(In thousands)
Deferred taxes
Accrued employee benefits	$	9,235	$	—		$	9,235
Accrued postretirement benefits		2,126		—			2,126
Accrued environmental costs		556		—			556
Inventory differences		258		(8,612	)		(8,354	)
Deferred turnaround costs		—		(356	)		(356	)
Prepayments and other		4,458		(2,874	)		1,584

Total current⁽¹⁾		16,633		(11,842	)		4,791
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(207,861	)		(207,861	)
Accrued postretirement benefits		15,761		—			15,761
Accrued environmental costs		947		—			947
Deferred turnaround costs		—		(23,326	)		(23,326	)
Investment in HEP		74,640		—			74,640
Other		11,626		(3,722	)		7,904

Total noncurrent		102,974		(234,909	)		(131,935	)

Total	$	119,607	$	(246,751	)	$	(127,144	)

At December 31, 2011 we had a net operating loss carryforward of $46.9 million in the state of Colorado that is scheduled to be utilized in 2012 through 2029 and a Kansas income tax credit of $31.2 million that is scheduled to be utilized in 2012 through 2019. These amounts are reflected in other current and non-current deferred tax assets.

The total amount of unrecognized tax benefits as of December 31, 2011, was $2.4 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


Liability for Unrecognized Tax Benefits	(In thousands)
Balance at January 1, 2011	$	1,864
Additions due to merger with Frontier		22,577
Additions based on tax positions related to the current year		—
Additions for tax positions of prior years		73
Reductions for tax positions of prior years		(204	)
Settlements		(21,679	)
Reductions for statute limitations		(206	)

Balance at December 31, 2011	$	2,425

Included in the unrecognized tax benefits at December 31, 2011 are $2.2 million of 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. During the year ended December 31, 2011, we recognized a $12.1 million tax benefit (net of interest) as a component 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 do not expect that unrecognized tax benefits for tax positions taken with respect to 2011 and prior years will significantly change over the next twelve months.

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We are subject to U.S. federal income tax, Arizona, Iowa, New Mexico, Utah, Oklahoma, Kansas and Colorado 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, 2005. In late 2010, the Internal Revenue Service commenced an examination of our U.S. federal tax returns for the tax years ended December 31, 2006, 2007, 2008 and 2009. We anticipate that these audits will be completed by the end of 2012.

NOTE 16: Stockholders’ Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2011, 2010 and 2009 is presented below:


	Years Ended December 31,
	2011			2010			2009
				(In thousands)
Common shares outstanding at beginning of year		106,529,376			106,132,538			99,886,440
Common shares issued in connection with merger with Frontier		103,270,002			—			—
Common shares issued to Sinclair in connection with Tulsa East facility acquisition		—			—			5,578,310
Issuance of common stock upon exercise of stock options		—			80,400			90,000
Issuance of restricted stock, excluding restricted stock with performance feature		512,880			282,886			308,156
Vesting of performance units		233,134			140,286			293,328
Vesting of restricted stock with performance feature		124,332			12,300			99,438
Forfeitures of restricted stock		(3,730	)		(30,084	)		(3,266	)
Purchase of treasury stock⁽¹⁾		(1,333,348	)		(88,950	)		(119,868	)

Common shares outstanding at end of year		209,332,646			106,529,376			106,132,538

(1)	Includes 747,225, 88,950 and 119,868 shares purchased in 2011, 2010 and 2009, respectively, 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.

During the years ended December 31, 2011, 2010 and 2009, we withheld shares of our common stock from certain employees in the amounts of $24.9 million, $1.2 million and $1.2 million, respectively. These withholdings were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted and performance shares in the case of officers and employees who elected to have shares withheld from vested amounts in order to pay such taxes. The amounts withheld in 2011 also reflect withholdings associated with “change in control” instant vesting provisions of the legacy Frontier stock awards.

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NOTE 17: 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, 2011
Unrealized loss on available-for-sale securities	$	(516	)	$	(199	)	$	(317	)
Unrealized gain on hedging activities		176,936			67,732			109,204
Retirement medical obligation adjustment		(3,515	)		(1,367	)		(2,148	)
Minimum pension liability adjustment		(71	)		(28	)		(43	)

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


Year Ended December 31, 2010
Unrealized gain on available-for-sale securities	$	114		$	42		$	72
Unrealized loss on hedging activities		(923	)		275			(1,198	)
Retirement medical obligation adjustment		(238	)		(93	)		(145	)
Minimum pension liability adjustment		(1,470	)		(572	)		(898	)

Other comprehensive loss		(2,517	)		(348	)		(2,169	)
Less other comprehensive loss attributable to noncontrolling interest		(1,623	)		—			(1,623	)

Other comprehensive loss attributable to HollyFrontier stockholders	$	(894	)	$	(348	)	$	(546	)


Year Ended December 31, 2009
Unrealized gain on available-for-sale securities	$	409		$	158		$	251
Unrealized gain on hedging activities		3,726			663			3,063
Retirement medical obligation adjustment		742			289			453
Minimum pension liability adjustment		12,497			4,862			7,635

Other comprehensive income		17,374			5,972			11,402
Less other comprehensive income attributable to noncontrolling interest		2,021			—			2,021

Other comprehensive income attributable to HollyFrontier stockholders	$	15,353		$	5,972		$	9,381

The temporary unrealized gain (loss) on available-for-sale securities is due to changes in market prices of securities.

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


	December 31,
	2011			2010
	(In thousands)
Pension obligation adjustment	$	(22,715	)	$	(22,672	)
Retiree medical obligation adjustment		(4,042	)		(1,894	)
Unrealized gain on securities available-for-sale		134			451
Unrealized gain (loss) on hedging activities, net of noncontrolling interest		104,496			(2,131	)

Accumulated other comprehensive income (loss)	$	77,873		$	(26,246	)

NOTE 18: Retirement Plans

Retirement Plan

We sponsored a non-contributory defined benefit retirement plan that covered most legacy Holly non-union employees hired prior to January 1, 2007 and union employees hired prior to July 1, 2010. This retirement plan was closed to new entrants effective either January 1, 2007 (for non-union employees) or July 1, 2010 (for union employees). Effective January 1, 2012, no additional benefits will be accrued under this plan for non-union employees participants. There will be a transition benefit over the next three years for active employees who have been transitioned to a new defined contribution plan. Additionally, there will be changes in the employer contribution feature of our defined contribution plan for all non-union employees.

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Our funding policy for this defined benefit retirement plan is to make annual contributions of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2011 and 2010:


	Years Ended December 31,
	2011			2010
	(In thousands)
Change in plan’s benefit obligation
Pension plan’s benefit obligation — beginning of year	$	94,083		$	81,170
Service cost		5,070			4,595
Interest cost		5,125			5,154
Benefits paid		(1,347	)		(4,825	)
Actuarial loss		16,108			7,989
Settlements paid		(10,510	)		—
Curtailment		(15,151	)		—

Pension plan’s benefit obligation — end of year	$	93,378		$	94,083


Change in pension plan assets
Fair value of plan assets—beginning of year	$	64,490		$	55,618
Actual return on plan assets		(1,235	)		8,297
Benefits paid		(1,347	)		(4,825	)
Employer contributions		10,000			5,400
Settlements paid		(10,510	)		—

Fair value of plan assets—end of year	$	61,398		$	64,490


Funded status
Under-funded balance	$	(31,980	)	$	(29,593	)


Amounts recognized in consolidated balance sheets Accrued pension liability	$	(31,980	)	$	(29,593	)

Amounts recognized in accumulated other comprehensive loss
Actuarial loss	$	(35,094	)	$	(33,750	)
Prior service cost		(966	)		(2,420	)

Total	$	(36,060	)	$	(36,170	)

The accumulated benefit obligation was $86.1 million and $75.4 million at December 31, 2011 and 2010, respectively. The measurement dates used for our retirement plan were December 31, 2011 and 2010.

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

		$000000000			$000000000
	December 31,
	2011			2010
Discount rate		4.60	%		5.65	%
Rate of future compensation increases		4.00	%		4.00	%

Net periodic pension expense consisted of the following components:


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Service cost — benefit earned during the year	$	5,070		$	4,595		$	4,314
Interest cost on projected benefit obligations		5,125			5,154			4,943
Expected return on plan assets		(5,230	)		(4,576	)		(3,843	)
Amortization of prior service cost		390			390			390
Amortization of net loss		2,126			2,196			3,815
Effect of settlements		3,951			—			—
Effect of curtailment		1,065			—			—

Net periodic pension expense	$	12,497		$	7,759		$	9,619

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

		$0000000			$0000000			$0000000
	Years Ended December 31,
	2011			2010			2009
Discount rate		5.65	%		6.20	%		6.50	%
Rate of future compensation increases		4.00	%		4.00	%		4.00	%
Expected long-term rate of return on assets		8.00	%		8.50	%		8.50	%

The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2012 are as follows:


	(In thousands)
Actuarial loss	$	2,337
Prior service cost		185

Total	$	2,522

At year end, our retirement plan assets were allocated as follows:


				Percentage of Plan Assets at Year End
Asset Category	Target Allocation 2012			December 31, 2011			December 31, 2010
Debt securities		60	%		62	%		30	%
Equity securities		32	%		30	%		66	%
Alternative investments		8	%		8	%		4	%

Total		100	%		100	%		100	%

The investment policy developed for the HollyFrontier Corporation Pension Plan (the “Plan”) has been designed exclusively for the purpose of providing the highest probabilities of delivering benefits to Plan members and beneficiaries. Among the factors considered in developing the investment policy are: the Plans’ primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation.

The most important component of the investment strategy is the asset allocation between the various classes of securities available to the Plan for investment purposes. The current target asset allocation is 32% equity investments, 60% fixed income investments and 8% alternative investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization and international stocks. Debt investments include a blend of domestic and global debt instruments. Alternative investments include a single fund that may invest in hedge funds, private equity, debt or real estate funds or other investments. The equity investments are valued using quoted market prices, a Level 1 input and debt investments are valued using quoted market prices for similar type investments, a Level 2 input. The alternative investments may be valued using significant other observable or unobservable inputs, Level 2 or 3 inputs. See Note 4, Financial Instruments, for information on Level 1, 2 and 3 inputs.

The overall expected long-term rate of return on Plan assets is 6.5% and is estimated using a financial simulation model of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient.

We expect to contribute between zero and $20 million to the retirement plan in 2012. Benefit payments, which reflect expected future service, are expected to be paid as follows: $5.9 million in 2012; $7.6 million in 2013; $7.2 million in 2014; $6.4 million in 2015, $6.7 million in 2016 and $38.4 million in 2017-2021.

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, no additional benefits will be accrued under this plan. We expensed $0.6 million, $0.6 million and $0.7 million for the years ended December 31, 2011, 2010 and 2009, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.7 million and $6.2 million at December 31, 2011 and 2010, respectively. As of December 31,

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2011, the projected benefit obligation under this plan was $6.7 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.4 million in 2012; $0.5 million in 2013; $1.5 million in 2014; $0.4 million in 2015; $0.4 million in 2016; and $2.2 million in 2017-2021.

Defined Contribution Plans

We have defined contribution “401(k)” plans that cover substantially all employees. Our contributions are based on employee’s compensation and partially match employee contributions. We expensed $9.7 million, $5.5 million and $5 million for the years ended December 31, 2011, 2010 and 2009, respectively, in connection with these plans.

Postretirement Medical Plans

We provide postretirement medical benefits to certain eligible employees. These plans are unfunded and provide differing levels of benefits dependent upon hire date and work location. Not all of our employees are covered by these plans at December 31, 2011.

The following table sets forth the changes in the benefit obligation and plan assets of our postretirement plans for the years ended December 31, 2011 and 2010:


	Years Ended December 31,
	2011			2010
	(In thousands)
Change in plans’ benefit obligation
Postretirement plans’ benefit obligation — beginning of year	$	7,862		$	6,622
Service cost		1,569			926
Interest cost		2,193			351
Participant contributions		460			244
Amendments		(5,387	)		—
Benefits paid		(1,105	)		(661	)
Plan combinations		62,632			—
Actuarial loss		9,079			380

Postretirement plans’ benefit obligation — end of year	$	77,303		$	7,862

Change in plan assets
Fair value of plan assets—beginning of year	$	—		$	—
Employer contributions		645			417
Participant contributions		460			244
Benefits paid		(1,105	)		(661	)

Fair value of plan assets—end of year	$	—		$	—

Funded status
Under-funded balance	$	(77,303	)	$	(7,862	)

Amounts recognized in consolidated balance sheets
Accrued postretirement liability	$	(77,303	)	$	(7,862	)

Amounts recognized in accumulated other comprehensive loss
Actuarial loss	$	11,631		$	2,667
Transition obligation		—			434
Prior service cost		(4,997	)		—

Total	$	6,634		$	3,101

The accumulated benefit obligation was $77.3 million and $7.9 million at December 31, 2011 and 2010, respectively. The measurement dates used for our postretirement plans were December 31, 2011 and 2010. Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.6 million in 2012; $2 million in 2013; $2.3 million in 2014; $2.6 million in 2015; $3 million in 2016; and $21.4 million in 2017 through 2021.

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


	December 31,
	2011			2010
Discount rate		4.60	%		5.25	%
Current health care trend rate		8.40	%		8.70	%
Ultimate health care trend rate		5.00	%		5.00	%
Year rate reaches ultimate trend rate		2023			2023

Net periodic postretirement expense consisted of the following components:


	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Service cost – benefit earned during the year	$	1,569	$	926	$	583
Interest cost on projected benefit obligations		2,193		351		400
Amortization of transition obligation		44		44		44
Amortization of net loss		114		98		139

Net periodic postretirement expense	$	3,920	$	1,419	$	1,166

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


	Years Ended December 31,
	2011			2010			2009
Discount rate		5.75	%		5.50	%		6.25	%
Current health care trend rate		8.70	%		9.00	%		10.00	%
Ultimate health care trend rate		5.00	%		5.00	%		6.00	%
Year rate reaches ultimate trend rate		2023			2023			2017

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	$	351	$	(270	)
Interest cost	$	416	$	(305	)
Year-end accumulated postretirement benefit obligation	$	16,917	$	(11,911	)

NOTE 19: Lease Commitments

We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2011, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows:


	(in thousands)
2012	$	31,888
2013		29,589
2014		27,259
2015		20,260
2016		16,412
Thereafter		8,947

Total	$	134,355

Rental expense charged to operations was $27 million, $13.3 million and $11.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. Rental expense for the years ended December 31, 2011, 2010 and 2009 includes $7.4 million, $7.1 million and $7.1 million, respectively, of rental expense attributable to the operations of HEP.

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NOTE 20: Contingencies and Contractual Obligations

We are a party to various litigation and proceedings which 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.

Contractual Obligations

We have various long-term purchase obligations under certain crude oil and feedstock arrangements to ensure we have an adequate supply of crude oil and certain resources used to operate our refineries. The substantial majority of our purchase obligations are based on market prices or rates. These contracts expire in 2012 through 2023.

We also have contractual obligations under agreements with third parties for the transportation and storage of crude oil, natural gas and feedstocks to our refineries under contracts expiring in 2016 through 2024.

NOTE 21: 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, which includes the UNEV Pipeline. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.

The Refining segment represents the aggregate operations of El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt. 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 logistic 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. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon USA, Inc., by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. The HEP segment also includes a 25% interest in SLC Pipeline that serves refineries in the Salt Lake City, Utah area. 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. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, 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).

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	Refining⁽¹⁾		HEP		Corporate and Other			Consolidations and Eliminations			Consolidated Total
	(In thousands)
Year Ended December 31, 2011
Sales and other revenues	$	15,392,430	$	213,566	$	1,247		$	(167,715	)	$	15,439,528
Depreciation and amortization	$	122,437	$	31,530	$	6,568		$	(828	)	$	159,707
Income (loss) from operations	$	1,739,068	$	113,258	$	(120,833	)	$	55		$	1,731,548
Capital expenditures	$	148,699	$	39,337	$	186,205		$	—		$	374,241
Total assets	$	7,018,804	$	992,408	$	2,421,140		$	(117,731	)	$	10,314,621

Year Ended December 31, 2010
Sales and other revenues	$	8,287,000	$	182,114	$	415		$	(146,600	)	$	8,322,929
Depreciation and amortization	$	84,587	$	29,062	$	4,562		$	(682	)	$	117,529
Income (loss) from operations	$	242,466	$	92,386	$	(69,654	)	$	(2,200	)	$	262,998
Capital expenditures	$	186,441	$	25,103	$	1,688		$	—		$	213,232
Total assets	$	2,490,193	$	669,820	$	573,531		$	(32,069	)	$	3,701,475

Year Ended December 31, 2009
Sales and other revenues	$	4,789,821	$	146,561	$	(636	)	$	(101,478	)	$	4,834,268
Depreciation and amortization	$	67,347	$	24,599	$	6,805		$	—		$	98,751
Income (loss) from operations	$	71,281	$	70,373	$	(60,239	)	$	(1,104	)	$	80,311
Capital expenditures	$	266,648	$	32,999	$	2,904		$	—		$	302,551
Total assets	$	2,142,317	$	641,775	$	392,007		$	(30,160	)	$	3,145,939

(1)	The Refining segment reflects the operations of the El Dorado and Cheyenne Refineries beginning July 1, 2011 (date of Holly-Frontier merger) and the operations of our Tulsa West and East facilities beginning June 1, 2009 and December 1, 2009, respectively (dates of acquisition).

HEP segment revenues from external customers were $46.4 million, $36 million and $45.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

NOTE 22: 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 42% ownership interest, 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 financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of 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.”

Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.

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Condensed Consolidating Balance Sheet


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)		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,575,891		$	(3,358	)	$	3,102		$	—		$	1,575,635	$	3,269	$	—		$	1,578,904
Marketable securities		210,886			753			—			—			211,639		—		—			211,639
Accounts receivable		8,317			1,437,434			3,074			—			1,448,825		34,071		(35,661	)		1,447,235
Intercompany accounts receivable (payable)		3,075,563			(3,374,597	)		299,034			—			—		—		—			—
Inventories		—			1,113,136			—			—			1,113,136		1,483		—			1,114,619
Income taxes receivable		87,273			4			—			—			87,277		—		—			87,277
Prepayments and other assets		19,379			202,428			1,089			—			222,896		1,161		(4,607	)		219,450

Total current assets		4,977,309			(624,200	)		306,299			—			4,659,408		39,984		(40,268	)		4,659,124

Properties, plants and equipment, net		26,702			2,043,257			398,984			—			2,468,943		590,243		(6,281	)		3,052,905
Marketable securities (long-term)		50,067			—			—			—			50,067		—		—			50,067
Investment in subsidiaries		1,160,801			593,118			(240,060	)		(1,513,859	)		—		—		—			—
Intangibles and other assets		19,329			2,242,197			—			—			2,261,526		364,893		(73,894	)		2,552,525

Total assets	$	6,234,208		$	4,254,372		$	465,223		$	(1,513,859	)	$	9,439,944	$	995,120	$	(120,443	)	$	10,314,621


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	23,497		$	2,232,831		$	10,999		$	—		$	2,267,327	$	11,406	$	(35,661	)	$	2,243,072
Income taxes payable		(109,320	)		149,686			—			—			40,366		—		—			40,366
Accrued liabilities		53,390			103,636			1,236			—			158,262		16,285		(4,607	)		169,940
Deferred income tax liabilities		192,073			(16,390	)		—			—			175,683		—		—			175,683

Total current liabilities		159,640			2,469,763			12,235			—			2,641,638		27,691		(40,268	)		2,629,061
Long-term debt		651,261			54,070			—			—			705,331		598,761		(89,350	)		1,214,742
Deferred income tax liabilities		162,021			295,893			856			—			458,770		—		4,951			463,721
Other long-term liabilities		116,443			52,892			—			—			169,335		4,000		(2,138	)		171,197
Distributions in excess of inv in HEP		—			220,953			—			—			220,953		—		(220,953	)		—
Equity – HollyFrontier Corporation		5,144,843			1,160,801			452,132			(1,612,933	)		5,144,843		364,668		(305,501	)		5,204,010
Equity – noncontrolling interest		—			—			—			99,074			99,074		—		532,816			631,890

Total liabilities and equity	$	6,234,208		$	4,254,372		$	465,223		$	(1,513,859	)	$	9,439,944	$	995,120	$	(120,443	)	$	10,314,621

Condensed Consolidating Balance Sheet


December 31, 2010	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP		Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	230,082		$	(9,035	)	$	7,651		$	—		$	228,698	$	403	$	—		$	229,101
Marketable securities		—			1,343			—			—			1,343		—		—			1,343
Accounts receivable		1,683			991,778			—			—			993,461		22,508		(22,853	)		993,116
Intercompany accounts receivable (payable)		(1,401,580	)		981,691			419,889			—			—		—		—			—
Inventories		—			400,165			—			—			400,165		202		—			400,367
Income taxes receivable		51,034			—			—			—			51,034		—		—			51,034
Prepayments and other assets		10,210			20,942			—			—			31,152		573		(3,251	)		28,474

Total current assets		(1,108,571	)		2,386,884			427,540			—			1,705,853		23,686		(26,104	)		1,703,435

Properties, plants and equipment, net		17,177			1,017,877			236,648			—			1,271,702		492,098		(7,109	)		1,756,691
Investment in subsidiaries		2,273,159			595,888			(393,011	)		(2,476,036	)		—		—		—			—
Intangibles and other assets		8,569			77,600			—			—			86,169		154,036		1,144			241,349

Total assets	$	1,190,334		$	4,078,249		$	271,177		$	(2,476,036	)	$	3,063,724	$	669,820	$	(32,069	)	$	3,701,475


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,170		$	1,319,316		$	3,575		$	—		$	1,330,061	$	10,238	$	(22,853	)	$	1,317,446
Accrued liabilities		25,512			28,145			797			—			54,454		21,206		(3,251	)		72,409

Total current liabilities		32,682			1,347,461			4,372			—			1,384,515		31,444		(26,104	)		1,389,855

Long-term debt		289,509			55,706			—			—			345,215		482,271		(16,925	)		810,561
Other long-term liabilities		42,655			27,521			—			—			70,176		10,809		—			80,985
Deferred income tax liabilities		126,160			259			565			—			126,984		—		4,951			131,935
Distributions in excess of inv in HEP		—			374,143			—			—			374,143		—		(374,143	)		—
Equity – HollyFrontier Corporation		699,328			2,273,159			266,240			(2,539,399	)		699,328		145,296		(147,205	)		697,419
Equity – noncontrolling interest		—			—			—			63,363			63,363		—		527,357			590,720

Total liabilities and equity	$	1,190,334		$	4,078,249		$	271,177		$	(2,476,036	)	$	3,063,724	$	669,820	$	(32,069	)	$	3,701,475

-101-

Condensed Consolidating Statement of 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)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	1,008		$	15,392,446		$	223		$	—		$	15,393,677		$	213,566		$	(167,715	)	$	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			1,185			—			688,566			62,202			(2,687	)		748,081
General and administrative expenses		111,093			2,445			—			—			113,538			6,576			—			120,114
Depreciation and amortization		4,165			123,082			1,758			—			129,005			31,530			(828	)		159,707

Total operating costs and expenses		115,258			13,657,241			2,943			—			13,775,442			100,308			(167,770	)		13,707,980

Income (loss) from operations		(114,250	)		1,735,205			(2,720	)		—			1,618,235			113,258			55			1,731,548
Other income (expense):
Earnings of equity method investments		1,771,022			38,546			40,674			(1,809,820	)		40,422			2,552			(40,674	)		2,300
Interest income (expense)		(38,619	)		(2,729	)		55			—			(41,293	)		(38,210	)		2,464			(77,039	)
Merger transaction costs		(15,114	)		—			—			—			(15,114	)		—			—			(15,114	)

		1,717,289			35,817			40,729			(1,809,820	)		(15,985	)		(35,658	)		(38,210	)		(89,853	)

Income before income taxes		1,603,039			1,771,022			38,009			(1,809,820	)		1,602,250			77,600			(38,155	)		1,641,695
Income tax provision		581,757			—			—			—			581,757			234			—			581,991

Net income		1,021,282			1,771,022			38,009			(1,809,820	)		1,020,493			77,366			(38,155	)		1,059,704
Less net income attributable to noncontrolling interest		—			—			—			789			789			—			(37,096	)		(36,307	)

Net income attributable to HollyFrontier stockholders	$	1,021,282		$	1,771,022		$	38,009		$	(1,809,031	)	$	1,021,282		$	77,366		$	(75,251	)	$	1,023,397

Condensed Consolidating Statement of Income


Year Ended December 31, 2010	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	412		$	8,287,000		$	3		$	—		$	8,287,415		$	182,114		$	(146,600	)	$	8,322,929
Operating costs and expenses:
Cost of products sold		—			7,510,172			185			—			7,510,357			—			(143,208	)		7,367,149
Operating expenses		2,411			449,534			32			—			451,977			52,947			(510	)		504,414
General and administrative expenses		62,130			990			—			—			63,120			7,719			—			70,839
Depreciation and amortization		3,745			85,517			(113	)		—			89,149			29,062			(682	)		117,529

Total operating costs and expenses		68,286			8,046,213			104			—			8,114,603			89,728			(144,400	)		8,059,931

Income (loss) from operations		(67,874	)		240,787			(101	)		—			172,812			92,386			(2,200	)		262,998
Other income (expense):
Earnings of equity method investments		265,367			30,036			30,069			(295,403	)		30,069			2,393			(30,069	)		2,393
Interest income (expense)		(33,838	)		(5,456	)		45			—			(39,249	)		(36,245	)		2,466			(73,028	)

		231,529			24,580			30,114			(295,403	)		(9,180	)		(33,852	)		(27,603	)		(70,635	)

Income before income taxes		163,655			265,367			30,013			(295,403	)		163,632			58,534			(29,803	)		192,363
Income tax provision		59,016			—			—			—			59,016			296			—			59,312

Net income		104,639			265,367			30,013			(295,403	)		104,616			58,238			(29,803	)		133,051
Less net income attributable to noncontrolling interest		—			—			—			23			23			—			(29,110	)		(29,087	)

Net income attributable to HollyFrontier stockholders	$	104,639		$	265,367		$	30,013		$	(295,380	)	$	104,639		$	58,238		$	(58,913	)	$	103,964

-102-

Condensed Consolidating Statement of Income


Year Ended December 31, 2009	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	3,346		$	4,785,781		$	58		$	—		$	4,789,185		$	146,561		$	(101,478	)	$	4,834,268

Operating costs and expenses:
Cost of products sold		—			4,336,973			900			—			4,337,873			—			(99,865	)		4,238,008
Operating expenses		—			313,361			—			—			313,361			44,003			(509	)		356,855
General and administrative expenses		51,648			1,318			(209	)		—			52,757			7,586			—			60,343
Depreciation and amortization		3,928			68,956			1,268			—			74,152			24,599			—			98,751


Total operating costs and expenses		55,576			4,720,608			1,959			—			4,778,143			76,188			(100,374	)		4,753,957


Income (loss) from operations		(52,230	)		65,173			(1,901	)		—			11,042			70,373			(1,104	)		80,311

Other income (expense):
Equity in earnings of subsidiaries		96,266			31,643			33,052			(127,909	)		33,052			—			(33,052	)		—
Interest income (expense)		(13,713	)		1,096			44			—			(12,573	)		(21,490	)		(1,238	)		(35,301	)
Other income (expense)		(1,480	)		1,480			—			—			—			1,986			(67	)		1,919
Acquisition costs		—			(3,126	)		—			—			(3,126	)		(1,356	)		1,356			(3,126	)

		81,073			31,093			33,096			(127,909	)		17,353			(20,860	)		(33,001	)		(36,508	)


Income (loss) from continuing operations before income taxes		28,843			96,266			31,195			(127,909	)		28,395			49,513			(34,105	)		43,803

Income tax provision		10,295			—			—			—			10,295			20			(2,855	)		7,460


Income from continuing operations		18,548			96,266			31,195			(127,909	)		18,100			49,493			(31,250	)		36,343

Income from discontinued operations		—			—			—			—			—			19,780			(2,854	)		16,926


Net income		18,548			96,266			31,195			(127,909	)		18,100			69,273			(34,104	)		53,269

Less net income attributable to noncontrolling interest		—			—			—			448			448			—			(34,184	)		(33,736	)


Net income attributable to HollyFrontier stockholders	$	18,548		$	96,266		$	31,195		$	(127,461	)	$	18,548		$	69,273		$	(68,288	)	$	19,533

Condensed Consolidating Statement of Cash Flows


Year Ended December 31, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	1,933,208		$	(690,318	)	$	42,655		$	1,285,545		$	93,119		$	(40,273	)	$	1,338,391

Cash flows from investing activities
Additions to properties, plants and equipment		(7,585	)		(163,002	)		(164,317	)		(334,904	)		—			—			(334,904	)
Additions to properties, plants and equipment – HEP		—			—			—			—			(39,337	)		—			(39,337	)
Investment in Sabine Biofuels		(9,125	)		—			—			(9,125	)		—			—			(9,125	)
Increase in cash due to merger with Frontier		182			872,557			—			872,739			—			—			872,739
Purchases of marketable securities		(561,899	)		—			—			(561,899	)		—			—			(561,899	)
Sales and maturities of marketable securities		301,020			—			—			301,020			—			—			301,020

		(277,407	)		709,555			(164,317	)		267,831			(39,337	)		—			228,494


Cash flows from financing activities
Net repayments under credit agreements – HEP		—			—			—			—			41,000			—			41,000
Proceeds from issuance of common units – HEP		—			—			—			—			75,815			—			75,815
Repayments under promissory notes		—			77,100			—			77,100			(77,100	)		—			—
Purchase of treasury stock		(42,795	)		—			—			(42,795	)		—			—			(42,795	)
Principal tender on senior notes		(8,203	)		—			—			(8,203	)		—			—			(8,203	)
Contribution from joint venture partner		—			(89,500	)		123,000			33,500			—			—			33,500
Capital contribution		—			—			(5,887	)		(5,887	)		5,887			—			—
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
Repayments under financing obligation		—			(1,160	)					(1,160	)		—			—			(1,160	)
Purchase of units for HEP restricted grants		—			—			—			—			(1,641	)		—			(1,641	)
Deferred financing costs		(8,665	)		—			—			(8,665	)		(3,150	)		—			(11,815	)
Other financing activities, net		—			—			—			—			(221	)		(359	)		(580	)

		(309,992	)		(13,560	)		117,113			(206,439	)		(50,916	)		40,273			(217,082	)


Cash and cash equivalents
Increase (decrease) for the period		1,345,809			5,677			(4,549	)		1,346,937			2,866			—			1,349,803
Beginning of period		230,082			(9,035	)		7,651			228,698			403			—			229,101

End of period	$	1,575,891		$	(3,358	)	$	3,102		$	1,575,635		$	3,269		$	—		$	1,578,904

-103-

Condensed Consolidating Statement of Cash Flows


Year Ended December 31, 2010	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	140,934		$	74,234		$	1,268		$	216,436		$	103,168		$	(36,349	)	$	283,255

Cash flows from investing activities
Additions to properties, plants and equipment		(1,573	)		(105,434	)		(81,122	)		(188,129	)		—			—			(188,129	)
Additions to properties, plants and equipment – HEP		—			—			—			—			(60,629	)		35,526			(25,103	)
Proceeds from sale of assets		—			39,040			—			39,040			—			(39,040	)		—

		(1,573	)		(66,394	)		(81,122	)		(149,089	)		(60,629	)		(3,514	)		(213,232	)


Cash flows from financing activities
Net repayments under credit agreements – HEP		—			—			—			—			(47,000	)		—			(47,000	)
Proceeds from issuance of senior notes – HEP		—			—			—			—			147,540			—			147,540
Repayments under financing obligation		—			(1,444	)		—			(1,444	)		—			416			(1,028	)
Purchase of treasury stock		(1,368	)		—			—			(1,368	)		—			—			(1,368	)
Contribution from joint venture partner		—			(57,000	)		80,500			23,500			—			—			23,500
Dividends		(31,868	)		—			—			(31,868	)		—			—			(31,868	)
Purchase price in excess of transferred basis in assets		—			54,046			—			54,046			(57,560	)		3,514			—
Distributions to noncontrolling interest		—			—			—			—			(84,426	)		35,933			(48,493	)
Excess tax benefit from equity based compensation		(1,094	)		—			—			(1,094	)		—			—			(1,094	)
Deferred financing costs		(2,627	)		—			—			(2,627	)		(494	)		—			(3,121	)
Purchase of units for HEP restricted grants		—			—			—			—			(2,704	)		—			(2,704	)
Other		118			—			—			118			—			—			118

		(36,839	)		(4,398	)		80,500			39,263			(44,644	)		39,863			34,482


Cash and cash equivalents
Increase (decrease) for the period		102,522			3,442			646			106,610			(2,105	)		—			104,505
Beginning of period		127,560			(12,477	)		7,005			122,088			2,508			—			124,596


End of period	$	230,082		$	(9,035	)	$	7,651		$	228,698		$	403		$	—		$	229,101

Condensed Consolidating Statement of Cash Flows


Year Ended December 31, 2009	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(277,912	)	$	448,020		$	308		$	170,416		$	68,195		$	(27,066	)	$	211,545

Cash flows from investing activities
Additions to properties, plants and equipment		(2,904	)		(215,343	)		(51,305	)		(269,552	)		—			—			(269,552	)
Additions to properties, plants and equipment – HEP		—			—			—			—			(128,079	)		95,080			(32,999	)
Purchases of marketable securities		(175,892	)		—			—			(175,892	)		—			—			(175,892	)
Sales and maturities of marketable securities		230,281			—			—			230,281			—			—			230,281
Acquisition of Tulsa Refineries		74,000			(341,141	)		—			(267,141	)		—			—			(267,141	)
Acquisition of logistic assets		—			—			—			—			(25,665	)		—			(25,665	)
Investment in SLC Pipeline		—			—			—			—			(25,500	)		—			(25,500	)
Proceeds from the sale of assets		—			83,280			—			83,280			—			(83,280	)		—
Proceeds from sale of Rio Grande		—			—			—			—			31,865			—			31,865

Net cash provided by (used for) investing activities		125,485			(473,204	)		(51,305	)		(399,024	)		(147,379	)		11,800			(534,603	)


Cash flows from financing activities
Net borrowings under credit agreement—HEP		—			—			—			—			6,000			—			6,000
Proceeds from issuance of common units—HEP		—			—			—			—			133,035			—			133,035
Dividends		(30,123	)		—			—			(30,123	)		—			—			(30,123	)
Distributions to noncontrolling interest		—			—			—			—			(62,688	)		29,488			(33,200	)
Purchase of treasury stock		(1,214	)		—			—			(1,214	)		—			—			(1,214	)
Contribution from joint venture partner		—			(39,450	)		54,600			15,150			—			—			15,150
Excess tax benefit from equity based compensation		(1,209	)		—			—			(1,209	)		—			—			(1,209	)
Deferred financing costs		(8,842	)		—			—			(8,842	)		—			—			(8,842	)
Proceeds from issuance of senior notes		287,925			—			—			287,925			—			—			287,925
Proceeds from Plains financing transaction		—			40,000			—			40,000			—			—			40,000
Other financing activities, net		134			13,339			—			13,473			76			(14,222	)		(673	)


Net cash provided by financing activities		246,671			13,889			54,600			315,160			76,423			15,266			406,849


Cash and cash equivalents
Increase (decrease) for the period		94,244			(11,295	)		3,603			86,552			(2,761	)		—			83,791
Beginning of period		33,316			(1,182	)		3,402			35,536			5,269			—			40,805

End of period	$	127,560		$	(12,477	)	$	7,005		$	122,088		$	2,508		$	—		$	124,596

-104-

NOTE 23: 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 accounting for 10% or more of our annual revenues. Sinclair accounted for $2,035.1 million (13%) and $1,616 million (19%) of our revenues for the years ended December 31, 2011 and 2010, respectively, and Shell Oil accounted for $1,540.6 million (10%) of our revenues for the year ended December 31, 2011. We had no significant customers accounting for 10% or more of our annual revenues in 2009. Our export sales were to an affiliate of PEMEX and accounted for $370 million (2%), $323.2 million (4%) and $188.6 million (4%) of our revenues for the years ended December 31, 2011, 2010 and 2009, respectively.

NOTE 24: Quarterly Information (Unaudited)


	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Year
	(In thousands, except per share data)
Year Ended December 31, 2011
Sales and other revenues	$	2,326,585		$	2,967,133	$	5,173,398	$	4,972,412	$	15,439,528
Operating costs and expenses	$	2,167,486		$	2,636,954	$	4,304,191	$	4,599,349	$	13,707,980
Income from operations	$	159,099		$	330,179	$	869,207	$	373,063	$	1,731,548
Income before income taxes	$	140,022		$	313,794	$	835,769	$	352,110	$	1,641,695
Net income attributable to HollyFrontier stockholders	$	84,694		$	192,235	$	523,088	$	223,380	$	1,023,397
Net income per share attributable to HollyFrontier stockholders—basic	$	0.80		$	1.80	$	2.50	$	1.07	$	6.46
Net income per share attributable to HollyFrontier stockholders—diluted	$	0.79		$	1.79	$	2.48	$	1.06	$	6.42
Dividends per common share	$	0.075		$	0.075	$	0.588	$	0.600	$	1.338
Average number of shares of common stock outstanding:
Basic		106,614			106,730		209,583		209,319		158,486
Diluted		107,266			107,340		210,579		210,159		159,294
Year Ended December 31, 2010
Sales and other revenues	$	1,874,290		$	2,145,860	$	2,090,988	$	2,211,791	$	8,322,929
Operating costs and expenses	$	1,897,034		$	2,013,696	$	1,983,370	$	2,165,831	$	8,059,931
Income (loss) from operations	$	(22,744	)	$	132,164	$	107,618	$	45,960	$	262,998
Income (loss) before income taxes	$	(39,926	)	$	112,320	$	90,884	$	29,085	$	192,363
Net income (loss) attributable to HollyFrontier stockholders	$	(28,094	)	$	66,162	$	51,177	$	14,719	$	103,964
Net income (loss) per share attributable to HollyFrontier stockholders—basic	$	(0.26	)	$	0.62	$	0.48	$	0.14	$	0.98
Net income (loss) per share attributable to HollyFrontier stockholders—diluted	$	(0.26	)	$	0.62	$	0.48	$	0.13	$	0.97
Dividends per common share	$	0.075		$	0.075	$	0.075	$	0.075	$	0.300
Average number of shares of common stock outstanding:
Basic		106,188			106,412		106,420		106,516		106,436
Diluted		106,188			106,816		107,134		107,246		107,218

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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 as of December 31, 2011.

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 2011 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 is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 16, 2012 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 is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 16, 2012 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 is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 16, 2012 and is incorporated herein by reference.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by Item 404 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 16, 2012 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 is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 16, 2012 and is incorporated herein by reference.

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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		67

Consolidated Balance Sheets at December 31, 2011 and 2010		68

Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009		69

Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009		70

Consolidated Statements of Equity for the years ended December 31, 2011, 2010 and 2009		71

Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009		72

Notes to Consolidated Financial Statements		73

(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 111 to 121 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)

/s/ Michael C. Jennings

Michael C. Jennings

Chief Executive Officer

Date: February 28, 2012

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	Chief Executive Officer and	February 28, 2012
Michael C. Jennings	President

/s/ Douglas S. Aron	Executive Vice President and
Douglas S. Aron	Chief Financial Officer	February 28, 2012
	(Principal Financial Officer)

/s/ Scott C. Surplus	Vice President and Controller	February 28, 2012
Scott C. Surplus	(Principal Accounting Officer)

/s/ Denise C. McWatters	Vice President, General	February 28, 2012
Denise C. McWatters	Counsel and Secretary

/s/ Matthew P. Clifton	Executive Chairman	February 28, 2012
Matthew P. Clifton

/s/ Douglas Y. Bech	Director	February 28, 2012
Douglas Y. Bech

/s/ Buford P. Berry	Director	February 28, 2012
Buford P. Berry

/s/ Leldon Echols	Director	February 28, 2012
Leldon Echols

/s/ R. Kevin Hardage	Director	February 28, 2012
R. Kevin Hardage

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/s/ Robert J. Kostelnik	Director	February 28, 2012
Robert J. Kostelnik

/s/ James H. Lee	Director	February 28, 2012
James H. Lee

/s/ Robert G. McKenzie	Director	February 28, 2012
Robert G. McKenzie

/s/ Franklin Myers	Director	February 28, 2012
Franklin Myers

/s/ Michael E. Rose	Director	February 28, 2012
Michael E. Rose

/s/ Tommy A. Valenta	Director	February 28, 2012
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, by and 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, by and 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, by and between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (R&M) (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 as of 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 Form 8-K Current Report 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 Form 8-K Current Report filed November 8, 2011, File No. 1-03876).

4.1		Indenture, dated February 28, 2005, among Holly Energy Partners, L.P. and Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).

4.2		First Supplemental Indenture, dated March 10, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225).

4.3		Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225).

4.4		Third Supplemental Indenture, dated June 11, 2009, among Lovington-Artesia, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).

4.5		Fourth Supplemental Indenture, dated June 29, 2009, among HEP SLC, LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).

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4.6		Fifth Supplemental Indenture, dated July 13, 2009, among HEP Tulsa LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).

4.7		Sixth Supplemental Indenture, dated December 15, 2009, among Roadrunner Pipeline, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).

4.8		Seventh 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 4.1 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

4.9		Eighth 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 4.2 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

4.10		Ninth Supplemental Indenture, dated as of 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 4.12 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).

4.11		Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).

4.12		Form of Notation of Guarantee (included as Exhibit E to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).

4.13		Indenture, dated as of September 17, 2008, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.1 of Frontier’s Form 8-K Current Report filed September 17, 2008, File Number 1-07627).

4.14		First Supplemental Indenture, dated as of September 17, 2008, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated September 17, 2008, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.2 of Frontier’s Form 8-K Current Report filed September 17, 2008, File Number 1-07627).

4.15		Second Supplemental Indenture, dated as of May 26, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated September 17, 2008, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.1 of Frontier’s Form 8-K Current Report filed May 27, 2011, File Number 1-07627).

4.16		Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated September 17, 2008, providing for the issuance of 8.5% Senior Notes due 2016) (incorporated by reference to Exhibit 4.2 of Registrant’s Form 8-K Current Report filed July 8, 2011, File No. 1-03876).

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4.17		Form of global note for 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 of Frontier’s Form 8-K Current Report filed September 17, 2008, File Number 1-07627).

4.18		Indenture, dated June 10, 2009, among Holly Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee, relating to Holly Corporation’s 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 Form 8-K Current Report filed June 8, 2009, File No. 1-03876).

4.19		First Supplemental Indenture, dated June 14, 2011, among Holly Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee, relating to HollyFrontier Corporation’s 9.875% Senior Notes due 2017 (incorporated by reference to Exhibit 4.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 1-03876).

4.20		Second Supplemental Indenture, dated July 18, 2011, among HollyFrontier Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee (supplemental to Indenture dated June 10, 2009, providing for the issuance of 9.875% Senior Notes due 2017) (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).

4.21		Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp. and each of the guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 11, 2010, File No. 1-32225).

4.22		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 its quarterly period ended June 30, 2010, File No. 1-32225).

4.23		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 its quarterly period ended June 30, 2010, File No. 1-32225).

4.24		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 4.12 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).

4.25		Indenture, dated as of November 22, 2010, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee, providing for the issuance of 6⁷/₈% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Frontier’s Form 8-K Current Report dated November 22, 2010, File Number 1-07627).

4.26		First Supplemental Indenture, dated as of November 22, 2010, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated November 22, 2010, providing for the issuance of 6⁷/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.2 of Frontier’s Form 8-K Current Report dated November 22, 2010, File Number 1-07627).

4.27		Second Supplemental Indenture, dated as of May 26, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated November 22, 2010, providing for the issuance of 6⁷/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.2 of Frontier’s Form 8-K Current Report dated May 27, 2011, File Number 1-07627).

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4.28		Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated November 22, 2010, providing for the issuance of 6 7/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report filed July 8, 2011, File No. 1-03876).

4.29		Form of global note for 6 7/8% Senior Notes due 2018 (incorporated by reference to Exhibit 4.3 of Frontier’s Form 8-K Current Report filed November 22, 2010, File Number 1-07627).

10.1		Option Agreement, dated January 31, 2008, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 5, 2008, File No. 1-03876).

10.2		First Amendment to Option Agreement, dated February 11, 2010, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.2 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.3		Amended and Restated Intermediate Pipelines Agreement, dated June 1, 2009, by and among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Holly Energy Partners, L.P.’s Form 8-K Current Report filed June 5, 2009, File No. 1-32225).

10.4		Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C., and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.4 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.5		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).

10.6		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 Form 8-K Current Report filed August 6, 2009, File No. 1-32225).

10.7		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).

10.8		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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10.9		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 Form 8-K Current Report filed August 6, 2009, File No. 1-32225).

10.10		Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009, by and 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).

10.11		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 Registrants Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2011, File No. 1-03876).

10.12		Amended and Restated Refined Product Pipelines and Terminals Agreement, dated December 1, 2009, by and 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).

10.13		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).

10.14		Pipeline Throughput Agreement, dated December 1, 2009, by and 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).

10.15		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).

10.16		First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated March 31,2010, by and among 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 April 6, 2010, File No. 1-03876).

10.17		Amendment to First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated June 11, 2010, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

10.18		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).

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10.19		Second Amended and Restated Pipelines, Tankage, and Loading Rack Throughput Agreement, dated August 31, 2011 (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed September 1, 2011, File No. 1-03876).

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

10.21		Pipeline Systems Operating Agreement, dated February 8, 2010, by and 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).

10.22		First Amendment to Pipeline Systems Operating Agreement, dated March 31, 2010, by and 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).

10.23		Loading Rack Throughput Agreement (Lovington), dated March 31, 2010, by and 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).

10.24		First Amended and Restated Lease and Access Agreement (East Tulsa), dated March 31, 2010, by and among Holly Refining & Marketing-Tulsa, LLC, 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).

10.25		LLC Interest Purchase Agreement, dated November 9, 2011, by and 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).

10.26+		First Amended and Restated Tankage, Loading Rack and Crude Oil Receiving Throughput Agreement (Cheyenne), dated November 9, 2011, by and between Frontier Refining LLC and Cheyenne Logistics LLC.

10.27+		First Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated November 9, 2011, by and between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.

10.28		Sixth Amended and Restated Omnibus Agreement, dated November 9, 2011, by and among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.4 of Registrant’s Current Report on Form 8-K filed November 10, 2011, File No. 1-03876).

10.29		Lease and Access Agreement (Cheyenne), dated November 9, 2011, by and 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).

10.30		Lease and Access Agreement (El Dorado), dated November 9, 2011, by and 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).

10.31*		Holly Corporation Stock Option Plan as adopted at the Annual Meeting of Stockholders of Holly Corporation on December 13, 1990 (incorporated by reference to Exhibit 4(i) of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1991, File No. 1-03876).

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10.32*		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).

10.33*		Amendment No. 1 to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated on May 24, 2007 (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).

10.34*		Second Amendment to the Holly 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).

10.35*		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).

10.36*		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).

10.37*		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).

10.38*		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).

10.39*		First Amendment to Performance Share Unit Agreement (incorporated by reference to Exhibit 10.16 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).

10.40*		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).

10.41*		Holly Corporation Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

10.42*		Holly Energy Partners, L.P. Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

10.43*		Form of Executive Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.44*		Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.45*		Form of Director Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.46*		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).

10.47*		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).

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10.48*		Executive Restricted Stock Agreement, dated March 12, 2010, by and between Holly Corporation and Matthew P. Clifton (incorporated by reference to Exhibit 10.8 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).

10.49*		Executive Restricted Stock Agreement, dated March 12, 2010, by and between Holly Corporation and David L. Lamp (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).

10.50*		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).

10.51*		Waiver Agreement, dated as of February 21, 2011, by and between Holly Corporation and Matthew P. Clifton thereto (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 1-03876).

10.52*		Waiver Agreement, dated as of February 21, 2011, by and between Holly Corporation and Bruce R. Shaw (incorporated by reference to Exhibit 10.10 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 1-03876).

10.53*		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).

10.54*		Retention and Assumption Agreement, dated as of February 21, 2011, by and among Frontier Oil Corporation, Holly Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form 8-K filed on February 21, 2011).

10.55*		Retention and Assumption Agreement, dated as of February 21, 2011, by and among Frontier Oil Corporation, Holly Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8-K filed on February 21, 2011).

10.56*		HollyFrontier Corporation Omnibus Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 of Registrant’s Form 8-K Current Report filed July 8, 2011, File No. 1-03876).

10.57*		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).

10.58*		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).

10.59*		Frontier Deferred Compensation Plan (previously named Wainoco Deferred Compensation Plan dated October 29, 1993 (incorporated by reference to Exhibit 10.19 to Frontier’s Annual Report on Form 10-K filed March 17, 1995).

10.60*		Frontier Deferred Compensation Plan for Directors (previously named Wainoco Deferred Compensation Plan for Directors dated May 1, 1994 and incorporated by reference to Exhibit 10.20 to Frontier’s Annual Report on Form 10-K filed March 17, 1995).

10.61*		Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit/Restricted Stock Agreement (incorporated by reference to Exhibit 4.8 to Frontier’s Form S-8 filed April 27, 2006).

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10.62*		Form of Indemnification Agreement by and between Frontier and each of its officers and directors (incorporated by reference to Exhibit 10.41 to Frontier’s Annual Report Form 10-K filed February 28, 2007).

10.63*		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.64*		Amendment to Executive and Change in Control Severance Agreement, dated April 28, 2009, between Frontier Oil Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form 8-K filed May 01, 2009).

10.65*		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.4 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.66*		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Gerald B. Faudel (incorporated by reference to Exhibit 10.6 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.67*		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James M. Stump (incorporated by reference to Exhibit 10.15 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.68*		Executive Change in Control Severance Agreement, dated April 28, 2009, between Frontier Oil Corporation and Joshua Goodmanson (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8-K filed May 01, 2009).

10.69*		Executive Change in Control Severance Agreement, dated September 9, 2009, between Frontier Oil Corporation and Kevin D. Burke (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form 8-K filed September 09, 2009).

10.70*		Executive Change in Control Severance Agreement, effective as of June 1, 2010 by and between Frontier Oil Corporation and Paige A. Kester (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form filed November 4, 2010).

10.71*		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.16 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.73*		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.18 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.74*		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Gerald B. Faudel (incorporated by reference to Exhibit 10.20 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.75*		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James M. Stump (incorporated by reference to Exhibit 10.29 to Frontier’s Form 8-K filed January 2, 2009).

10.76*		Executive Severance Agreement, dated April 28, 2009, between Frontier Oil Corporation and Joshua Goodmanson (incorporated by reference to Exhibit 10.3 to Frontier’s Current Report on Form 8-K filed May 01, 2009).

10.77*		Executive Severance Agreement, dated September 9, 2009, between Frontier Oil Corporation and Kevin D. Burke (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8- K filed September 09, 2009).

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10.78*		Executive Severance Agreement, effective as of June 1, 2010 by and between Frontier Oil Corporation and Paige A. Kester (incorporated by reference to Exhibit 10.1 to Frontier’s Quarterly Report on Form 10-Q filed on November 4, 2010).

10.79*+		Form of Indemnification Agreement by and between HollyFrontier Corporation and each of its officers and directors.

10.80		Credit Agreement dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, and 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 Form 8-K Current Report filed July 8, 2011, File No. 1-03876).

10.81		First Amendment to Credit Agreement dated as of August 24, 2011 by and among HollyFrontier Corporation and certain subsidiaries of HollyFrontier Corporation, as borrowers, Union Bank, N.A., as administrative agent, and each of the financial institutions party thereto as lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report filed August 30, 2011, File No. 001-03876).

10.82		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 Form 8-K Current Report filed July 8, 2011, File No. 1-03876).

10.83		Frontier Products Offtake Agreement El Dorado Refinery, dated as of October 19, 1999 by and 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, Eight Amendment to the Agreement dated 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 and Refining Company’s Quarterly Report on Form 10-Q filed August 7, 2008).

10.84		Sixteenth Amendment dated November 1, 2009, to the Frontier Products Offtake Agreement El Dorado Refinery, dated as of October 19, 1999 by and 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 and Refining Company’s Annual Report on Form 10-K filed February 25, 2010).

10.85		Master Crude Oil Purchase and Sale Agreement, 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 and Refining Company’s Quarterly Report on Form 10-Q filed November 4, 2010).

10.86		Guaranty dated November 1, 2010 made 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 and Refining Company’s Quarterly Report on Form 10-Q filed November 4, 2010).

21.1+		Subsidiaries of Registrant.

23.1+		Consent of Independent Registered Public Accounting Firm.

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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 the fiscal year ended December 31, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Comprehensive Income, and (vi) Notes to the Consolidated Financial Statements.

+	Filed herewith.

++Furnished

electronically herewith.

*	Constitutes management contracts or compensatory plans or arrangements.

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