Edgar Filing: HollyFrontier Corp

HFC 12-31-2012 10K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________________________

FORM 10-K

_________________________________________________________________

(Mark One)



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

For the fiscal year ended December 31, 2012



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to ____________

Commission File Number 1-3876

_________________________________________________________________

HOLLYFRONTIER CORPORATION

(Exact name of registrant as specified in its charter)

_________________________________________________________________



Delaware		75-1056913
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2828 N. Harwood, Suite 1300 Dallas, Texas		75201-1507
(Address of principal executive offices)		(Zip Code)

(214) 871-3555

Registrant’s telephone number, including area code

_________________________________________________________________

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

Common Stock, $0.01 par value registered on the New York Stock Exchange.

Securities registered pursuant to 12(g) of the Act:

None.

_________________________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ý No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.

Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

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

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

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



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

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

On June 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the Common Stock, par value $0.01 per share, held by non-affiliates of the registrant was approximately $6.6 billion, based upon the closing price on the New York Stock Exchange on such date. (This is not deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.)

203,548,584 shares of Common Stock, par value $.01 per share, were outstanding on February 13, 2013.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 15, 2013, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference in Part III.

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TABLE OF CONTENTS



Item	Page

PART I

Forward-Looking Statements	3

Definitions	4

1 and 2. Business and properties	6
1A. Risk Factors	21
1B. Unresolved staff comments	30
3. Legal proceedings	31
4. Mine safety disclosures	32

PART II

5. Market for Registrant's common equity, related stockholder matters and issuer purchases of equity securities	33
6. Selected financial data	34
7. Management's discussion and analysis of financial condition and results of operations	35
7A. Quantitative and qualitative disclosures about market risk	50

Reconciliations to amounts reported under generally accepted accounting principles	50

8. Financial statements and supplementary data	54
9. Changes in and disagreements with accountants on accounting and financial disclosure	101
9A. Controls and procedures	101
9B. Other information	101

PART III

10. Directors, executive officers and corporate governance	101
11. Executive compensation	101
12. Security ownership of certain beneficial owners and management and related stockholder matters	101
13. Certain relationships and related transactions, and director independence	102
14. Principal accounting fees and services	102

PART IV

15. Exhibits, financial statement schedules	102

Signatures	103

Index to exhibits	105

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PART I

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10‑K contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business and Properties” in Items 1 and 2, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. These statements are based on management's beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors including, but not limited to:


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


•	the demand for and supply of crude oil and refined products;


•	the spread between market prices for refined products and market prices for crude oil;


•	the possibility of constraints on the transportation of refined products;


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


•	effects of governmental and environmental regulations and policies;


•	the availability and cost of our financing;


•	the effectiveness of our capital investments and marketing strategies;


•	our efficiency in carrying out construction projects;


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


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


•	general economic conditions; and


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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A and in conjunction with the discussion in this Form 10-K in “Management's Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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DEFINITIONS

Within this report, the following terms have these specific meanings:

“Alkylation” means the reaction of propylene or butylene (olefins) with isobutane to form an iso-paraffinic gasoline (inverse of cracking).

“Aromatic oil” is long chain oil that is highly aromatic in nature 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 alternative fuel produced from renewable biological resources.

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

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

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

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

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

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

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

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

“HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.

“Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.

“LPG” means liquid petroleum gases.

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

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

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

“MMBTU” means one million British thermal units.

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

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

“Refinery gross margin” means the difference between average net sales price and average product costs per produced barrel of refined products sold. This does not include the associated depreciation and amortization costs. Refinery gross margin is a non-GAAP performance measure.

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

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

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

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

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

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

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

“WTI” means West Texas Intermediate and is a grade of crude oil used as a common benchmark in oil pricing. WTI is a sweet crude oil and has a relatively low density.

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Items 1 and 2. Business and Properties

COMPANY OVERVIEW

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

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

We are principally an independent petroleum refiner that produces high-value 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. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by HollyFrontier's post-closing board of directors, Frontier merged with and into HollyFrontier, and HollyFrontier continued as the surviving corporation. This merger combined the legacy Frontier refinery operations consisting of refineries in El Dorado, Kansas (the “El Dorado Refinery”) and Cheyenne, Wyoming (the “Cheyenne Refinery”) with Holly’s legacy refinery operations to form HollyFrontier. The aggregate equity consideration paid in connection with the merger was $3.7 billion.

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

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 several acquisitions between 2009 and 2012. Information on these acquisitions can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”

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As of December 31, 2012, we:

•

owned and operated a petroleum refinery in El Dorado, Kansas, two refinery facilities located in Tulsa, Oklahoma, a refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming 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 44% interest in HEP, a consolidated VIE, which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, L.L.C. (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”) and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), 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). The financial information about our segments is discussed in Note 21 “Segment Information” in the Notes to Consolidated Financial Statements.

REFINERY OPERATIONS

Our refinery operations serve the Mid-Continent, Southwest and Rocky Mountain regions of the United States. We own and operate five complex refineries having an aggregate crude capacity of 443,000 barrels per stream day. Each of our refineries has the complexity to convert discounted, heavy and sour crude oils into a high percentage of gasoline, diesel and other high-value refined products. For 2012, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 50%, 31%, 6% and 3%, respectively, of our total refinery sales volumes.

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



	Years Ended December 31,
	2012		2011⁽¹⁰⁾		2010
Consolidated
Crude charge (BPD) ⁽¹⁾	415,210		315,000		221,440
Refinery throughput (BPD) ⁽²⁾	453,740		340,200		234,910
Refinery production (BPD) ⁽³⁾	442,730		331,890		225,980
Sales of produced refined products (BPD)	431,060		332,720		228,140
Sales of refined products (BPD) ⁽⁴⁾	443,620		340,630		232,100
Refinery utilization ⁽⁵⁾	93.7	%	89.9	%	86.5	%

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	Years Ended December 31,
	2012			2011⁽¹⁰⁾			2010
Consolidated
Average per produced barrel ⁽⁶⁾
Net sales	$	119.48		$	118.82		$	91.06
Cost of products ⁽⁷⁾	94.59			98.18			82.27
Refinery gross margin	24.89			20.64			8.79
Refinery operating expenses ⁽⁸⁾	5.49			5.36			5.08
Net operating margin	$	19.40		$	15.28		$	3.71

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.22		$	5.24		$	4.94

Feedstocks:
Sweet crude oil	51		%	56		%	53		%
Sour crude oil	22		%	23		%	35		%
Heavy sour crude oil	17		%	12		%	4		%
Black wax crude oil	2		%	2		%	3		%
Other feedstocks and blends	8		%	7		%	5		%
Total	100		%	100		%	100		%


(1)	Crude charge represents the barrels per day of crude oil processed at our refineries.


(2)	Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.


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


(4)	Includes refined products purchased for resale.


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


(6)	Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


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


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


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


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

Principal Products and Customers

Set forth below is information regarding our principal products.



	Years Ended December 31,
	2012		2011		2010
Consolidated
Sales of produced refined products:
Gasolines	50	%	48	%	49	%
Diesel fuels	31	%	32	%	31	%
Jet fuels	6	%	5	%	5	%
Fuel oil	2	%	2	%	2	%
Asphalt	3	%	4	%	3	%
Lubricants	3	%	3	%	5	%
Gas oil / intermediates	—	%	2	%	2	%
LPG and other	5	%	4	%	3	%
Total	100	%	100	%	100	%

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

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We have several significant customers, of which two accounted for more than 10% of our business in 2012. For the year ended December 31, 2012, Shell Oil accounted for $2,323.6 million, or 12%, of our revenues and Sinclair accounted for $2,106.6 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. See Note 23 “Significant Customers” in the Notes to Consolidated Financial Statements for additional information on our significant customers.

Mid-Continent Region (El Dorado and Tulsa Refineries)

Facilities

The El Dorado Refinery is a high-complexity coking refinery with a 135,000 barrels per stream day capacity and the ability to process significant volumes of heavy and sour crudes. The Tulsa West and East refinery facilities are both located in Tulsa, Oklahoma. In 2011, we integrated certain refining processes of the Tulsa Refineries which effectively provides us with a highly complex refining operation having a combined crude processing rate of approximately 125,000 barrels per stream day. For 2012, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 48%, 29%, 9% and 5%, 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,
	2012			2011 ⁽¹⁰⁾			2010
Mid-Continent Region (El Dorado and Tulsa Refineries)
Crude charge (BPD) ⁽¹⁾	248,360			183,070			111,670
Refinery throughput (BPD) ⁽²⁾	269,760			194,310			113,100
Refinery production (BPD) ⁽³⁾	263,310			188,760			106,910
Sales of produced refined products (BPD)	254,350			188,020			107,780
Sales of refined products (BPD) ⁽⁴⁾	258,020			190,340			108,330
Refinery utilization ⁽⁵⁾	95.5		%	94.8		%	89.3		%

Average per produced barrel ⁽⁶⁾
Net sales	$	119.19		$	119.51		$	90.84
Cost of products ⁽⁷⁾	95.77			99.92			83.29
Refinery gross margin	23.42			19.59			7.55
Refinery operating expenses ⁽⁸⁾	4.83			5.04			4.94
Net operating margin	$	18.59		$	14.55		$	2.61

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	4.55		$	4.88		$	4.71

Feedstocks:
Sweet crude oil	70		%	82		%	92		%
Sour crude oil	8		%	4		%	5		%
Heavy sour crude oil	14		%	8		%	3		%
Other feedstocks and blends	8		%	6		%	—		%
Total	100		%	100		%	100		%

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

The El Dorado Refinery is located on 1,100 acres south of El Dorado, Kansas and is a fully integrated refinery. The principal 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.

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The Tulsa West facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa West facility consist of crude and vacuum distillation (with light ends recovery), naphtha hydrodesulfurization, catalytic reforming, propane de-asphalting, lubes extraction, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. Tulsa West facility's Supporting Infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains All American Pipeline, L.P. (“Plains”).

The Tulsa East facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa East facility consist of crude and vacuum distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. The Tulsa East facility's Supporting Infrastructure includes approximately 3.4 million barrels of tankage capacity on the refinery's premises, of which approximately 3.2 million barrels of tankage is owned by HEP.

Markets and Competition

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

The El Dorado Refinery faces competition from other Plains States and Mid-Continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of economies of scale, we believe that our competitors' higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries.

For the year ended December 31, 2012, sales to Shell represented approximately 35% of the El Dorado Refinery's total sales and 12% of our total consolidated sales. We have an offtake agreement with Shell Oil Products US (“Shell”) under which Shell purchases gasoline, diesel and jet fuel production of the El Dorado Refinery at market-based prices through December 2014. In 2012, we retained and marketed 76,000 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 pipelines owned and operated by Magellan. These pipelines connect the refinery to distribution channels throughout Colorado, Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, HEP's on-site truck and rail racks facilitate access to local refined product markets.

In conjunction with our acquisition of the Tulsa East facility in 2009, we entered a five-year offtake agreement through 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, 2012, sales to Sinclair represented approximately 36% of the Tulsa Refineries total sales and 10% 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 North America and to customers with operations in Central America and South America. The specialty lubricant products are high value products that provide a significantly higher margin contribution to the refinery. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural products are formulated as supplemental carriers for herbicides and as Environmental Protection Agency (“EPA”) registered pesticide oils, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive and candle-making markets. Our production represents approximately 6% of paraffinic oil capacity and 13% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.

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Principal Products

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



	Years Ended December 31,
	2012		2011		2010
Mid-Continent Region (El Dorado and Tulsa Refineries)
Sales of produced refined products:
Gasolines	48	%	44	%	38	%
Diesel fuels	29	%	32	%	31	%
Jet fuels	9	%	7	%	8	%
Fuel oil	1	%	—	%	—	%
Asphalt	2	%	4	%	5	%
Lubricants	5	%	6	%	11	%
Gas oil / intermediates	—	%	3	%	4	%
LPG and other	6	%	4	%	3	%
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 50,000 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.

Southwest Region (Navajo Refinery)

Facilities

The Navajo Refinery has a crude oil capacity of 100,000 barrels per stream day and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. For 2012, gasoline and diesel fuel (excluding volumes purchased for resale) represented 51% and 38%, respectively, of our Southwest sales volumes.

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



	Years Ended December 31,
	2012			2011 ⁽¹⁰⁾			2010
Southwest Region (Navajo Refinery)
Crude charge (BPD) ⁽¹⁾	93,830			83,700			83,900
Refinery throughput (BPD) ⁽²⁾	103,120			93,260			94,270
Refinery production (BPD) ⁽³⁾	100,810			91,810			92,050
Sales of produced refined products (BPD)	99,160			93,950			92,550
Sales of refined products (BPD) ⁽⁴⁾	104,620			98,540			95,790
Refinery utilization ⁽⁵⁾	93.8		%	83.7		%	83.9		%

Average per produced barrel ⁽⁶⁾
Net sales	$	122.62		$	118.76		$	90.37
Cost of products ⁽⁷⁾	95.70			98.40			83.12
Refinery gross margin	26.92			20.36			7.25
Refinery operating expenses ⁽⁸⁾	6.07			5.44			4.95
Net operating margin	$	20.85		$	14.92		$	2.30

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.84		$	5.48		$	4.86

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	Years Ended December 31,
	2012		2011 ⁽¹⁰⁾		2010
Southwest Region (Navajo Refinery)
Feedstocks:
Sweet crude oil	2	%	3	%	5	%
Sour crude oil	77	%	75	%	81	%
Heavy sour crude oil	12	%	11	%	4	%
Other feedstocks and blends	9	%	11	%	10	%
Total	100	%	100	%	100	%

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

The Navajo Refinery's Artesia, New Mexico facility is located on a 561-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, mild hydrocracking, isomerization, sulfur recovery and product blending units. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. Supporting Infrastructure includes approximately 2.0 million barrels of feedstock and product tankage, of which 0.2 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, petroleum products from the Navajo Refinery are transported 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 Phillips 66 and EnCana Corp.), Valero, Alon and Western Refining. Pipelines serving this market are owned by Magellan, NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines, 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 from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market.

New Mexico Markets

The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western Refining, Alon and WRB.

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We use a common carrier pipeline out of El Paso to serve the Albuquerque market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in Bloomfield, 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 as well as into southern Colorado and northern Arizona.

Principal Products

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



	Years Ended December 31,
	2012		2011		2010
Southwest Region (Navajo Refinery)
Sales of produced refined products:
Gasolines	51	%	52	%	57	%
Diesel fuels	38	%	34	%	32	%
Jet fuels	—	%	1	%	3	%
Fuel oil	6	%	6	%	4	%
Asphalt	2	%	4	%	2	%
LPG and other	3	%	3	%	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 barrels per stream day and the Woods Cross Refinery has a crude oil capacity of 31,000 barrels per stream day. The Cheyenne Refinery processes heavy Canadian crudes as well as local sweet crudes such as that produced from the Bakken shale and similar resources. The Woods Cross Refinery processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2012, gasoline and diesel fuel (excluding volumes purchased for resale) represented 55% and 32%, respectively, of our Rocky Mountain sales volumes.

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



	Years Ended December 31,
	2012			2011 ⁽¹⁰⁾			2010
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
Crude charge (BPD) ⁽¹⁾	73,020			48,230			25,870
Refinery throughput (BPD) ⁽²⁾	80,860			52,630			27,540
Refinery production (BPD) ⁽³⁾	78,610			51,320			27,020
Sales of produced refined products (BPD)	77,550			50,750			27,810
Sales of refined products (BPD) ⁽⁴⁾	80,980			51,750			27,980
Refinery utilization ⁽⁵⁾	88.0		%	84.3		%	83.5		%

Average per produced barrel ⁽⁶⁾
Net sales	$	116.44		$	116.37		$	94.26
Cost of products ⁽⁷⁾	89.29			91.33			75.54
Refinery gross margin	27.15			25.04			18.72
Refinery operating expenses ⁽⁸⁾	6.91			6.41			6.09
Net operating margin	$	20.24		$	18.63		$	12.63

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	6.63		$	6.18		$	6.15

Feedstocks:
Sweet crude oil	47		%	52		%	59		%
Sour crude oil	1		%	1		%	—		%
Heavy sour crude oil	31		%	24		%	6		%
Black wax crude oil	11		%	15		%	30		%
Other feedstocks and blends	10		%	8		%	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 1.9 million barrels of feedstock and product tankage, of which 1.8 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 $225.0 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 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 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, Wyoming refineries near Rawlins and in Casper owned by Sinclair and a refinery in Denver owned by Suncor. Five product pipelines also supply Denver, including three from outside the region. 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. In addition to our Woods Cross Refinery, local area refiners include Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and Phillips 66. 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 Phillips 66. Approximately 40% - 45% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under a long-term supply agreement.

Idaho, Wyoming, Eastern Washington and Nevada Markets

We supply a small percentage of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery ships refined products over 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. In 2012, we began shipping refined products to Las Vegas, Nevada via the UNEV Pipeline. The majority of the Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan's CalNev common carrier pipeline system.

Principal Products

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



	Years Ended December 31,
	2012		2011		2010
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
Sales of produced refined products:
Gasolines	55	%	56	%	63	%
Diesel fuels	32	%	31	%	30	%
Jet fuels	—	%	1	%	1	%
Fuel oil	2	%	1	%	1	%
Asphalt	5	%	6	%	3	%
LPG and other	6	%	5	%	2	%
Total	100	%	100	%	100	%

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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 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.

HOLLY ENERGY PARTNERS, L.P.

HEP is a Delaware limited partnership that trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States.

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

HEP's recent acquisitions (2009 through 2012) are summarized below:

2012 Acquisition

UNEV Interest Transaction

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

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 $150.0 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 $93.0 million, consisting of hydrocarbon storage tanks having approximately 2.0 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa East facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.

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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.

SLC Pipeline Joint Venture Interest

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

Rio Grande Pipeline Sale

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

Transportation Agreements

Agreements with HEP

HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2012, these agreements result in minimum annualized payments to HEP of $217.2 million.

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

Agreement with Alon

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

As of December 31, 2012, HEP's assets include:

Pipelines


•	approximately 810 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico;


•	approximately 510 miles of refined product pipelines that transport refined products from Alon's Big Spring refinery in Texas to its customers in Texas and Oklahoma;

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•	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;


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


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


•	crude receiving assets located at our Cheyenne Refinery.

Refined Product Terminals and Refinery Tankage


•	four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,300,000 barrels, that are integrated with HEP's refined product pipeline system that serves our Navajo Refinery;


•	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;


•	one refined product terminal near Mountain Home, Idaho, with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;


•	two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of approximately 500,000 barrels, that are integrated with HEP's refined product pipelines that serve Alon's Big Spring, Texas refinery;

•

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


•	a leased jet fuel terminal in Roswell, New Mexico;


•	on-site crude oil tankage at our Tulsa, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity of approximately 1,100,000 barrels; and


•	on-site crude oil, refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate storage capacity of approximately 8,200,000 barrels.

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

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

We lease approximately 60,000 square feet for our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires in 2021. Functions performed in the Dallas office include overall corporate management, refinery and HEP management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.

Employees and Labor Relations

As of December 31, 2012, we had 2,534 employees, of which 851 are currently covered by collective bargaining agreements having various expiration dates between 2015 and 2018. We consider our employee relations to be good.

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Regulation

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

Our operations and many of the products we manufacture are subject to certain requirements of the Federal Clean Air Act (“CAA”) as well as related state and local laws and regulations. Certain CAA regulatory programs applicable to our refineries require capital expenditures for the installation of certain air pollution control devices. Additionally, the EPA has the authority under the CAA to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. Subsequent rulemaking authorized by the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years.

Also, we are subject to the EPA's new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations on gasoline that impose reductions in the benzene content of our produced gasoline. Our Tulsa, Navajo and Woods Cross Refineries currently purchase benzene credits to meet these requirements. Our remaining refineries become subject to the regulation on January 1, 2014. Recently completed capital projects at our Tulsa, Navajo and Woods Cross Refineries and capital projects planned for completion at our Cheyenne Refinery in 2013 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 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. Additional changes in fuel standards to reduce vehicle emissions are expected to be proposed in 2013. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may, where required, cause us to make substantial capital expenditures and purchase credits at significant cost to enable our refineries to produce products that meet applicable requirements.

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

Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in conformance with legal authorization, such as pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.

We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.

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The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including the current and past owner or operator of the disposal site or sites from which there is a release of a “hazardous substance,” as well as persons that disposed of or arranged for the disposal or treatment of the hazardous substances at the site or sites. Under CERCLA, such persons may be subject to joint and several liability for such costs as the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In the course of our historical operations, as well as in our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may be subject to cleanup and cost recovery actions under CERCLA by a government entity or other third party. Similarly, locations now owned or operated by us, where third parties have disposed such hazardous substances in the past, may also be subject to cleanup and cost recovery actions under CERCLA. Under CERCLA, liable parties may seek contribution from other liable parties to share in the costs of cleanup. Some states have enacted laws similar to CERCLA which impose similar responsibilities and liabilities on responsible parties. It is also not uncommon for neighboring landowners and other third parties to file claims under state law for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.

We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from past releases of refined product and crude oil into the environment. As of December 31, 2012, we had an accrual of $88.9 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.

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

Insurance

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

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

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Item 1A.	Risk Factors

Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition or results of operations could be materially and adversely affected.

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

Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve, and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.

We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. For example, the reversal of certain existing pipelines or the construction of certain new pipelines transporting additional crude oil or refined products to markets that serve competing refineries could affect the market dynamic that has allowed us to take advantage of favorable pricing. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year. In general, prices for refined products are influenced by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on operating results therefore depends in part on how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings and cash flow. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial condition and results of operations.

We may not be able to successfully execute our business strategies to grow our business. Further, if we are unable to complete capital projects at their expected costs or in a timely manner, if we are unsuccessful in integrating the operations of assets we acquire, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.

One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including:


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

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•	compliance with or liability under environmental regulations;


•	unplanned increases in the cost of construction materials or labor;


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


•	severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, spills) affecting our facilities, or those of vendors and suppliers;


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


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


•	nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

For example, there may be a delay in obtaining the necessary permits or regulatory approvals for the expansion at the Woods Cross refinery, or our request for the necessary permits or regulatory approvals may be denied. If we are unable to complete capital projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flows could be materially and adversely affected. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new refinery processing unit, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new capital investments may not achieve our expected investment return, which could adversely affect our financial condition or results of operations.

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

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


•	diversion of management time and attention from our existing business;


•	challenges in managing the increased scope, geographic diversity and complexity of operations and inefficiencies that may result therefrom;


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


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


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


•	difficulties or delays in achieving anticipated operational improvements or benefits;


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


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

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

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We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under 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 or we may be required to sell assets. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or construction projects, take advantage of other business opportunities or respond to competitive pressures, comply with regulatory requirements, or meet our short-term or long-term working capital requirements, any of which could have a material adverse effect on our revenues and results of operations. Failure to comply with regulatory requirements in a timely manner or meet our short-term or long-term working capital requirements could subject us to regulatory action.

We 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.

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.

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Failure to appropriately manage occupational health and safety risks associated with our business could also adversely impact employees, communities, stakeholders, our reputation and our results of operations.

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

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

From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.

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

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the refined products we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which may require permits for emissions of GHGs from certain large stationary sources. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions were upheld by the D.C. Circuit, but numerous parties are expected to seek U.S. Supreme Court review of that decision in 2013. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating GHG emissions from refineries.

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

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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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. 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 major capital investment, various environmental compliance related projects, regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.

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

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

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

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage or destruction of property, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.

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The availability of adequate insurance may be affected by conditions in the insurance market over which we have no control, resulting in the inability to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase or, in some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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.

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

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

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

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

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

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.

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

To maintain or increase production levels at our refineries, we must continually contract for crude oil supplies from third parties. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil available to our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries or the potential operation of a new, converted or expanded crude oil pipeline that transports crude oil to other markets could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries' production capacities.

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

We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by 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 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. 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.

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.

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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 44% 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 2026. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to:


•	its reliance on its significant customers, including us;


•	competition from other pipelines;


•	environmental regulations affecting pipeline operations;


•	operational hazards and risks;


•	pipeline tariff regulations affecting the rates HEP can charge;


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


•	other financial, operational and legal risks.

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

For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” For risks related to HEP's business, see Item 1A of HEP's Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

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

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

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

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

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

The long-term impacts of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, are not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding continued global hostilities or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.

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

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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.

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

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

We may be unable to pay future regular and/or special dividends.

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

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

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

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

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

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

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

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

Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.

The operating and financial restrictions and covenants in our credit 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.

As of December 31, 2012, approximately 34% 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.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

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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.

Propane Pit - Woods Cross

In December 2011, the EPA conducted an inspection at Woods Cross and identified some alleged violations of the Chemical Accident Prevention and Risk Management Plan (“RMP”) requirements set forth in section 112(r)(7) of the Federal Clean Air Act and Part 68 of Title 40 of the Code of Federal Regulations. Following extended negotiations, Holly Refining & Marketing – Woods Cross LLC and the EPA on October 12, 2012 agreed to resolve this matter with a civil penalty of $115,000, subject to the parties' agreement on the final terms of two documents – an Administrative Compliance Order on Consent (“ACOC”) specifying the details of the closure of the Frozen Earth Propane Storage Pit and a Combined Complaint and Consent Agreement (“CCCA”) detailing the EPA allegations and resolution of those allegations. Neither of these agreements require Holly Refining & Marketing – Woods Cross LLC to admit or deny the EPA's allegations. As of December 14, 2012, the ACOC and CCCA were signed by all required parties and are now final.

Additional Environmental Matters

We are reporting the following proceedings to comply with SEC regulations which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. Our respective subsidiaries have or will develop corrective action plans regarding these disclosures that will be implemented in consultation with the respective federal and state agencies. It is not possible to predict the ultimate outcome of these proceedings, although none are currently expected to have a material effect on our consolidated financial position.

Frontier Refining LLC (“FR”), our wholly-owned subsidiary, has undertaken environmental audits at the Cheyenne Refinery regarding compliance with federal and state air quality and waste requirements. By letters dated October 5, 2012, and November 7, 2012, FR submitted reports to the EPA voluntarily disclosing non-compliance with certain emission limitations, reporting, and other provisions of a 2009 federal consent decree. By letter dated January 10, 2013, FR submitted to the EPA a voluntary self-disclosure of preliminary audit findings consistent with the EPA’s Audit Policy. By letter dated October 31, 2012, FR submitted a preliminary report to the Wyoming Department of Environmental Quality (“WDEQ”) voluntarily disclosing non-compliance with certain notification, reporting, and other provisions of the refinery's state air permits and other regulatory requirements. The Cheyenne Refinery also has four outstanding Notices of Violations issued in 2010, 2011 and 2013 that are subject to ongoing settlement negotiations with the WDEQ. Additional air, water and waste audits are ongoing or planned for the Cheyenne Refinery for 2013.

Ethanol Management Company LLC (“EMC”), our wholly-owned subsidiary, has undertaken an environmental audit at the terminal located in Henderson, Colorado regarding compliance with the hazardous waste requirements administered by the Colorado Department of Public Health and Environment (“CDPHE”). By letter dated November 7, 2012, EMC notified the CDPHE of non-compliance under hazardous waste regulations associated with waste water storage, and on February 4, 2013, the CDPHE notified EMC that this matter is formally closed and no action will be taken in response to the self-disclosure.

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

Other

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

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

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

In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. These programs may be discontinued at any time by the Board of Directors. The following table includes repurchases made under these programs during the fourth quarter of 2012.



Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Shares that May Yet Be Purchased under the Plans or Programs
October 2012	398,131	$	37.27	398,131	$	495,390,494
November 2012	26,100	$	37.95	26,100	$	494,399,956
December 2012 ⁽¹⁾	134,200	$	45.67	—	$	494,399,956
Total for October to December 2012	558,431			424,231

(1) The December 2012 shares repurchased were not purchased under our approved stock repurchase program, but rather pursuant to separate authority from our Board of Directors. These repurchases were made in the open market.

As of February 13, 2013, we had approximately 88,000 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 “Debt” in the Notes to Consolidated Financial Statements.

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Item 6.	Selected Financial Data

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



	Years Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands, except per share date)
FINANCIAL DATA ⁽¹⁾
For the period
Sales and other revenues	$	20,090,724		$	15,439,528		$	8,322,929		$	4,834,268		$	5,860,357
Income from continuing operations before income taxes	2,787,995			1,641,695			192,363			43,803			187,746
Income tax provision	1,027,962			581,991			59,312			7,460			64,028
Income from continuing operations	1,760,033			1,059,704			133,051			36,343			123,718
Income from discontinued operations, net of taxes ⁽²⁾	—			—			—			16,926			2,918
Net income	1,760,033			1,059,704			133,051			53,269			126,636
Less net income attributable to noncontrolling interest	32,861			36,307			29,087			33,736			6,078
Net income attributable to HollyFrontier stockholders	$	1,727,172		$	1,023,397		$	103,964		$	19,533		$	120,558
Earnings per share attributable to HollyFrontier stockholders - basic	$	8.41		$	6.46		$	0.98		$	0.20		$	1.20
Earnings per share attributable to HollyFrontier stockholders - diluted	$	8.38		$	6.42		$	0.97		$	0.20		$	1.19
Cash dividends declared per common share	$	3.10		$	1.34		$	0.30		$	0.30		$	0.30
Average number of common shares outstanding:
Basic	205,289			158,486			106,436			100,836			100,404
Diluted	206,184			159,294			107,218			101,206			101,098

Net cash provided by operating activities	$	1,662,687		$	1,338,391		$	283,255		$	211,545		$	155,490
Net cash provided by (used for) investing activities	$	(711,104	)	$	228,494		$	(213,232	)	$	(534,603	)	$	(57,777	)
Net cash provided by (used for) financing activities	$	(772,788	)	$	(217,082	)	$	34,482		$	406,849		$	(151,277	)

At end of period
Cash, cash equivalents and investments in marketable securities	$	2,393,401		$	1,840,610		$	230,444		$	125,819		$	94,447
Working capital	$	2,815,821		$	2,030,063		$	313,580		$	257,899		$	68,465
Total assets ⁽³⁾	$	10,328,997		$	9,576,243		$	3,049,951		$	2,766,318		$	1,728,293
Total debt⁽⁴⁾	$	1,336,238		$	1,214,742		$	810,561		$	707,458		$	370,914
Total equity	$	6,642,658		$	5,835,900		$	1,288,139		$	1,207,781		$	936,332


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


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


(3)	Prior period total assets have been recast to reflect a net amount due under contractual netting agreements. See Note 2 “Change in Accounting Principle” in the Notes to Consolidated Financial Statements.


(4)	Includes total HEP debt of $864.7 million, $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 on July 1, 2011. Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

Overview

We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate refineries having a combined crude oil processing capacity of 443,000 barrels per day that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Our refineries are located in El Dorado, Kansas (the El Dorado Refinery), Tulsa, Oklahoma (the Tulsa Refineries), which comprise two production facilities, the Tulsa West and East facilities, a petroleum refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross Refinery).

Our discussion of financial and operating results for the years ended December 31, 2012, 2011 and 2010 is presented in the following section.

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Results Of Operations

Financial Data



	Years Ended December 31,
	2012			2011 ⁽¹⁾			2010
	(In thousands, except per share data)
Sales and other revenues	$	20,090,724		$	15,439,528		$	8,322,929
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	15,840,643			12,680,078			7,367,149
Operating expenses (exclusive of depreciation and amortization)	994,966			748,081			504,414
General and administrative expenses (exclusive of depreciation and amortization)	128,101			120,114			70,839
Depreciation and amortization	242,868			159,707			117,529
Total operating costs and expenses	17,206,578			13,707,980			8,059,931
Income from operations	2,884,146			1,731,548			262,998
Other income (expense):
Earnings of equity method investments	2,923			2,300			2,393
Interest income	4,786			1,284			1,168
Interest expense	(104,186		)	(78,323		)	(74,196		)
Gain on sale of marketable securities	326			—			—
Merger transaction costs	—			(15,114		)	—
	(96,151		)	(89,853		)	(70,635		)
Income before income taxes	2,787,995			1,641,695			192,363
Income tax provision	1,027,962			581,991			59,312
Net income	1,760,033			1,059,704			133,051
Less net income attributable to noncontrolling interest	32,861			36,307			29,087
Net income attributable to HollyFrontier stockholders	$	1,727,172		$	1,023,397		$	103,964
Earnings per share attributable to HollyFrontier stockholders:
Basic	$	8.41		$	6.46		$	0.98
Diluted	$	8.38		$	6.42		$	0.97
Cash dividends declared per common share	$	3.10		$	1.34		$	0.30
Average number of common shares outstanding:
Basic	205,289			158,486			106,436
Diluted	206,184			159,294			107,218

(1) Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011. Assuming the merger had been consummated on January 1, 2010, pro forma revenues and net income for the years ended December 31, 2011 and 2010 are as follows:



	Years 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

Other Financial Data



	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Net cash provided by operating activities	$	1,662,687		$	1,338,391		$	283,255
Net cash provided by (used for) investing activities	$	(711,104	)	$	228,494		$	(213,232	)
Net cash provided by (used for) financing activities	$	(772,788	)	$	(217,082	)	$	34,482
Capital expenditures	$	335,263		$	374,241		$	213,232
EBITDA ⁽¹⁾	$	3,097,402		$	1,842,134		$	353,833

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(1)

Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

Our operations are organized into two reportable segments, Refining and HEP. See Note 21 “Segment Information” in the Notes to Consolidated Financial Statements for additional information on our reportable segments.

Refining Operating Data

Our refinery operations include the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries. The following tables set forth information, including non-GAAP performance measures about our consolidated refinery operations. The cost of products and refinery gross and net operating margins do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.



	Years Ended December 31,
	2012			2011⁽¹⁰⁾			2010
Consolidated
Crude charge (BPD) ⁽¹⁾	415,210			315,000			221,440
Refinery throughput (BPD) ⁽²⁾	453,740			340,200			234,910
Refinery production (BPD) ⁽³⁾	442,730			331,890			225,980
Sales of produced refined products (BPD)	431,060			332,720			228,140
Sales of refined products (BPD) ⁽⁴⁾	443,620			340,630			232,100
Refinery utilization ⁽⁵⁾	93.7		%	89.9		%	86.5		%

Average per produced barrel ⁽⁶⁾
Net sales	$	119.48		$	118.82		$	91.06
Cost of products ⁽⁷⁾	94.59			98.18			82.27
Refinery gross margin	24.89			20.64			8.79
Refinery operating expenses ⁽⁸⁾	5.49			5.36			5.08
Net operating margin	$	19.40		$	15.28		$	3.71

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.22		$	5.24		$	4.94


(1)	Crude charge represents the barrels per day of crude oil processed at our refineries.


(2)	Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.


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


(4)	Includes refined products purchased for resale.


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


(6)	Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


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


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


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


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

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

Summary

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

Sales and Other Revenues

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

Cost of Products Sold

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

Gross Refinery Margins

Gross refinery margin per produced barrel increased 21% from $20.64 for the year ended December 31, 2011 to $24.89 for the year ended December 31, 2012. This is due to the effects of a current year decrease in crude oil and feedstock prices along with slightly higher sales prices received on produced products sold. Gross refinery margin does not include the effects of depreciation and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.

Operating Expenses

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

General and Administrative Expenses

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

Depreciation and Amortization Expenses

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

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Interest Income

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

Interest Expense

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

Merger Transaction Costs

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

Income Taxes

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

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 $104.0 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 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 beginning July 1, 2011.

Sales and Other Revenues

Sales and other revenues 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 2010. 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 $36.0 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 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.

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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 31, 2011 and 2010, operating expenses include $61.1 million and $52.7 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 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 $33.3 million and $28.9 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 $5.0 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 $36.2 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 on 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 $582.0 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.

LIQUIDITY AND CAPITAL RESOURCES

HollyFrontier Credit Agreement

We have a $1 billion senior secured credit agreement (the “HollyFrontier Credit Agreement”) with Union Bank, N.A. as administrative agent and certain lenders from time to time party thereto. 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. At December 31, 2012, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $29.2 million under the HollyFrontier Credit Agreement.

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HEP Credit Agreement

HEP has a $550 million senior secured revolving credit facility that matures in June 2017 (the “HEP Credit Agreement”) and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $60 million sub-limit. At December 31, 2012, HEP was in compliance with all of its covenants, had outstanding borrowings of $421.0 million and no outstanding letters of credit under the HEP Credit Agreement.

HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no 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 ($286.8 million principal amount maturing June 2017)


•	6.875% senior notes ($150 million principal amount maturing November 2018)

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.

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

HollyFrontier Financing Obligation

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

HEP Senior Notes

HEP’s senior notes consist of the following:


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


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

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

The 8.25% and 6.5% HEP senior notes (collectively, the “HEP Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes.

Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

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Liquidity

We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our credit facilities will provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future. In addition, components of our growth strategy include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow.

As of December 31, 2012, our cash, cash equivalents and investments in marketable securities totaled $2.4 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 financial institutions or government entities with strong credit standings.

In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. These programs may be discontinued at any time by the Board of Directors. As of December 31, 2012, we have repurchased 6,775,729 shares at a cost of $205.6 million, with remaining authorization to repurchase $494.4 million under these stock repurchase programs.

Cash and cash equivalents increased $178.8 million for the year ended December 31, 2012. Cash provided by operating activities of $1,662.7 million exceeded net cash used for investing and financing activities of $711.1 million and $772.8 million, respectively. Working capital increased by $785.8 million during the year ended December 31, 2012.

Cash Flows – Operating Activities

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

Net cash flows provided by operating activities were $1,662.7 million for the year ended December 31, 2012 compared to $1,338.4 million for the year ended December 31, 2011, an increase of $324.3 million. Net income for the year ended December 31, 2012 was $1,760.0 million, an increase of $700.3 million compared to $1,059.7 million for the year ended December 31, 2011. Non-cash adjustments consisting of depreciation and amortization, gain on sale of equity securities, deferred income taxes, equity-based compensation expense and fair value changes to derivative instruments resulted in an increase to operating cash flows of $429.5 million for the year ended December 31, 2012 compared to $178.0 million for the same period in 2011. Changes in working capital items decreased cash flows by $398.0 million for the year ended December 31, 2012 compared to an increase of $147.3 million for the year ended December 31, 2011. The decrease in working capital items for the year ended December 31, 2012 was due principally to higher inventory levels and a decrease in income taxes payable and accrued liabilities due to timing differences of payments during the fourth quarter of 2012 relative to 2011. Additionally, for the year ended December 31, 2012, turnaround expenditures increased to $159.7 million from $32.0 million for the same period of 2011.

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 $178.0 million for the year ended December 31, 2011 compared to $154.3 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. The increase in working capital items for the year ended December 31, 2011 was due principally to the effects of higher levels of accrued liabilities at December 31, 2011 relative to 2010 as a result of increased income taxes and costs supporting our recently merged company. Additionally, turnaround expenditures were $32.0 million and $35.0 million for the years ended December 31, 2011 and 2010, respectively.

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Cash Flows – Investing Activities and Planned Capital Expenditures

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

Net cash flows used for investing activities were $711.1 million for the year ended December 31, 2012 compared to net cash flows provided by investing activities of $228.5 million for the year ended December 31, 2011, a decrease of $939.6 million. Investing activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July 1, 2011 merger with Frontier. Cash expenditures for properties, plants and equipment for 2012 decreased to $335.3 million from $374.2 million for the same period in 2011. These include HEP capital expenditures of $44.9 million and $216.2 million for the years ended December 31, 2012 and 2011, respectively, which include 2011 capital expenditures of $164.3 million to construct the UNEV Pipeline. Also for the years ended December 31, 2012 and 2011, we invested $671.6 million and $561.9 million, respectively, in marketable securities and received proceeds of $297.7 million and $301.0 million, respectively, from the sale or maturity of marketable securities.

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. Investing activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July 1, 2011 merger with Frontier. Cash expenditures for properties, plant and equipment for 2011 increased to $374.2 million compared to $213.2 million for 2010. These include HEP capital expenditures of $216.2 million and $109.5 million for the years ended December 31, 2011 and 2010, respectively. 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 $301.0 million from the sale of our marketable securities.

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 2013 is $320.0 million including both sustaining capital and major capital projects. We expect to spend approximately $400.0 million to $450.0 million in cash for capital projects appropriated in 2013 plus those appropriated in prior years but not yet completed. In addition, we expect to spend $156.0 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 2013 and expected cash spending is as follows:



	New Appropriation		Expected Cash Spending Range
	(In millions)
Location:
El Dorado	$	122.0	$	56.0	–	$	65.0
Tulsa	68.0		116.0		–	130.0
Navajo	22.0		28.0		–	33.0
Cheyenne	52.0		58.0		–	61.0
Woods Cross	41.0		130.0		–	146.0
Corporate and Other	15.0		12.0		–	15.0
Total	$	320.0	$	400.0	–	$	450.0

Type:
Sustaining	$	109.0	$	100.0	–	$	113.0
Reliability and Growth	177.0		196.0		–	220.0
Compliance and Safety	34.0		104.0		–	117.0
Total	$	320.0	$	400.0	–	$	450.0

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A significant portion of our current capital spending is associated with compliance-oriented capital improvements. This spending is required due to existing consent decrees (for projects including FCC unit flue gas scrubbers and tail gas treatment units), federal fuels regulations (particularly, MSAT2 which mandates a reduction in the benzene content of blended gasoline), refinery waste water treatment improvements and other similar initiatives. Our refinery operations and related emissions are highly regulated at both federal and state levels, and we invest in our facilities as needed to remain in compliance with these standards. Additionally, when faced with new emissions or fuels standards, we seek to execute projects that facilitate compliance and also improve the operating costs and/or yields of associated refining processes.

El Dorado Refinery

Newly appropriated capital projects at the El Dorado Refinery include naphtha fractionation, an additional hydrogen plant and a Low-Nox addition to the FCC unit flue gas scrubber. Continuing project work will include coke drum pressure reduction designed to improve liquid yields and a new tail gas treatment unit to reduce air emissions in compliance with the El Dorado Refinery's existing EPA consent decree.

Tulsa Refineries

New 2013 appropriations for the Tulsa Refineries include a gasoline-blending system and numerous infrastructure upgrades. We will continue spending on the conversion of our propane de-asphalt unit to ROSE technology and on our sulfur recovery project related to the refinery fuel gas system. This project will be completed in approximately the second quarter of 2013 and, in addition to facilitating compliance with our EPA consent, will also allow us to increase use of lower priced sour / heavy crude in Tulsa. Spending on maintenance capital items and general improvements continues at an elevated level at the Tulsa Refineries due to perceived opportunities.

Navajo Refinery

The Navajo Refinery capital spending in 2013 will be principally on previously approved capital appropriations as well as maintenance capital spending. Included among previously approved capital projects is a $25.0 million upgrade to the Navajo Refinery's waste water treatment system.

Cheyenne Refinery

We plan to install a new hydrogen plant at the Cheyenne Refinery and have appropriated this capital project as part of our 2013 budget. The hydrogen plant, along with a previously approved naphtha fractionation project, will allow us to reduce benzene content in Cheyenne gasoline production, while at the same time improving the refinery's overall liquid yields and light oils production. Previously appropriated projects still underway at Cheyenne include wastewater treatment plant improvements, a wet gas scrubber for the FCC unit to reduce air emissions, a redundant tail gas unit associated with sulfur recovery processes and additional investment in the waste water treatment plant to reduce selenium concentration in waste water.

Woods Cross Refinery

Newly appropriated capital for the Woods Cross Refinery consists of warehouse and office relocations to accommodate the refinery expansion and modernization program and of a new rail loading rack for intermediates and finished products associated with refining waxy crude oil. We continue to work on the $225.0 million refinery expansion project announced previously, with expected completion date in approximately the fourth quarter of 2014.

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

HEP

Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in its current year capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2013 HEP capital budget is comprised of $9.2 million for maintenance capital expenditures and $2.3 million for expansion capital expenditures.

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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. HEP has a second project recently approved which consists of the reactivation and conversion to crude oil service of a 70-mile, 8-inch petroleum products pipeline owned by HEP. This project also includes the expansion and extension of several of HEP's crude gathering systems and crude mainline pipes. Once in service, this system will be capable of transporting crude oil from southeast New Mexico to third-party common carrier pipelines in west Texas for further transport to major crude oil markets. This project is estimated to cost approximately $38.0 million and could be fully operational in late 2013.

Cash Flows – Financing Activities

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

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

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

Net cash flows used for 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, 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 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 $118.0 million and repaid $77.0 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. During 2010, we received and repaid $310.0 million in advances under the HollyFrontier Credit Agreement, paid $31.9 million in dividends 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 $66.0 million and repaid $113.0 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. UNEV Pipeline joint venture partner contributions received during the years ended December 31, 2011 and 2010 were $33.5 million and $23.5 million, respectively.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2012 in total and by period due beginning in 2013. The table below does not include our contractual obligations to HEP under our long-term transportation agreements as these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.

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			Payments Due by Period
Contractual Obligations and Commitments	Total		Less than 1 Year		1-3 Years		3-5 Years		Over 5 Years
HollyFrontier Corporation ^{(1) (2)}
Long-term debt - principal ⁽³⁾	$	473,123	$	1,477	$	3,546	$	291,326	$	176,774
Long-term debt - interest ⁽⁴⁾	219,830		42,959		85,324		69,426		22,121
Supply agreements ⁽⁵⁾	738,608		283,164		401,521		12,688		41,235
Transportation agreements ⁽⁶⁾	471,888		83,515		162,142		118,664		107,567
Other long-term obligations	16,216		7,184		6,582		2,450		—
Operating leases	76,222		22,319		33,464		14,431		6,008
	1,995,887		440,618		692,579		508,985		353,705

Holly Energy Partners
Long-term debt - principal ⁽⁷⁾	871,000		—		—		421,000		450,000
Long-term debt - interest ⁽⁸⁾	260,951		42,239		84,478		79,296		54,938
Pipeline operating and right of way leases	38,033		6,909		13,699		13,668		3,757
Other agreements	16,210		1,519		2,967		2,725		8,999
	1,186,194		50,667		101,144		516,689		517,694
Total	$	3,182,081	$	491,285	$	793,723	$	1,025,674	$	871,399

(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 $12.6 million as of December 31, 2012 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 15 “Income Taxes” in the Notes to Consolidated Financial Statements.


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


(3)	Our long-term debt consists of the $286.8 million principal balance on our 9.875% senior notes, the $150.0 million principal balance on our 6.875% senior notes and a long-term financing obligation having a principal balance of $36.3 million at December 31, 2012.


(4)	Interest payments consist of interest on our 9.875% and 6.875% senior notes and on our long-term financing obligation.


(5)	We have long-term supply agreements to secure certain quantities of crude oil, feedstock and other resources used in the production process at market prices. We have estimated future payments under these fixed-quantity agreements expiring between 2014 and 2024 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 2013 and 2024.


(7)	HEP's long-term debt consists of the $150.0 million and the $300.0 million principal balances on the 8.25% and 6.5% HEP senior notes and $421.0 million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement was amended in June 2012 and expires in 2017.


(8)	Interest payments consist of interest on the 6.5% and 8.25% HEP senior notes and interest on long-term debt under the HEP Credit Agreement. The interest rate on the HEP Credit Agreement debt was 2.46% at December 31, 2012.

CRITICAL ACCOUNTING POLICIES

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

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In the first quarter of 2012, we changed our policy of reporting certain same-party accounts receivable and payable amounts in the consolidated balance sheets to reflect a net amount due under contractual netting agreements. Prior to this change, we reported such amounts on a gross basis with a same-party receivable and payable balance presented separately in our balance sheet. GAAP permits a reporting entity to elect a policy of offsetting same party receivables and payables when such amounts are net settled under legally enforceable contractual setoff provisions. We believe that a net presentation is preferable because it more appropriately presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated with such assets and liabilities. Additionally, we believe a net presentation of such amounts conforms to the predominant practices used by others in our industry. We have applied this change in accounting principle on a retrospective basis and have recast our prior period financial statements. See Note 2 “Change in Accounting Policy” in the Notes to Consolidated Financial Statements for a summary of line items affected in our financial statements.

Variable Interest Entity

HEP is a VIE as defined under GAAP. A VIE is a legal entity whose equity owners do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly impact the entity's financial performance, the obligation to absorb the entity's expected losses or rights to expected residual returns. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP's 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.

Derivative Instruments

We have commodity price swap, interest rate swap, physical and NYMEX futures contracts that are measured at fair value and recognized as other assets or liabilities in our consolidated balance sheets. Changes in fair value to derivative instruments are recognized in earnings unless specific hedge accounting criteria is met. Derivatives meeting certain hedge accounting criteria are designated as “accounting hedges” and changes in fair value are recorded directly to other comprehensive income. These gains or losses are reclassified to earnings as the hedging instruments mature. Also, on a quarterly basis, hedge ineffectiveness on our accounting hedges is measured by comparing the change in fair value of the derivative contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is recognized in earnings. See Note 14 “Derivative Instruments and Hedging Activities” in the Notes to Consolidated Financial Statements.

Inventory Valuation

Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2012, 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, 2012, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $134.0 million. An actual valuation of inventory under the LIFO method is made at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management's estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.

Deferred Maintenance Costs

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

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Long-lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value, which is generally determined under an income approach using forecasted cash flows associated with the underlying asset. Estimates of future cash flows require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2012, 2011 and 2010.

Intangibles and Goodwill

Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized while intangible assets with finite useful lives are amortized on a straight-line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our analysis entails a comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. There were no impairments of intangible assets or goodwill during the years ended December 31, 2012, 2011 and 2010.

Contingencies

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

RISK MANAGEMENT

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

Commodity Price Risk Management

Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative contracts in the form of commodity price swaps and futures contracts to mitigate price exposure with respect to:


•	our inventory positions;


•	natural gas purchases;


•	costs of crude oil and related grade differentials;


•	prices of refined products; and


•	our refining margins.

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As of December 31, 2012, we have the following notional contract volumes related to all outstanding derivative contracts used to mitigate commodity price risk:



		Notional Contract Volumes by Year of Maturity
Contract Description	Total Outstanding Notional	2013	2014	2015	2016	2017	Unit of Measure

Natural gas price swap - long	96,000,000	19,200,000	19,200,000	19,200,000	19,200,000	19,200,000	MMBTU
WTI price swap - long	12,930,000	12,565,000	365,000	—	—	—	Barrels
Ultra-low sulfur diesel price swap - short	11,490,000	11,125,000	365,000	—	—	—	Barrels
Unleaded gasoline price swap - short	1,632,000	1,632,000	—	—	—	—	Barrels
WCS price swap - long	6,022,500	6,022,500	—	—	—	—	Barrels
WTI price swap - short	150,000	150,000	—	—	—	—	Barrels
NYMEX futures (WTI) - long	234,000	234,000	—	—	—	—	Barrels
NYMEX futures (WTI) - short	1,091,000	1,091,000	—	—	—	—	Barrels
Physical contracts - long	540,000	540,000	—	—	—	—	Barrels
Physical contracts - short	540,000	540,000	—	—	—	—	Barrels

The following sensitivity analysis provides the hypothetical effects of market price fluctuations to the commodity positions hedged under our derivative contracts:



	Derivative Fair Value Gain (Loss) at December 31,
Change in Underlying Commodity Prices of Hedged Positions	2012		2011
	(In thousands)
10% increase in underlying commodity prices	(29,230	)	(23,224	)
10% decrease in underlying commodity prices	29,230		23,224

Interest Rate Risk Management

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

As of December 31, 2012, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.25% as of December 31, 2012, which equaled an effective interest rate of 3.24%. This swap matures in February 2016. HEP has two additional interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.25% as of December 31, 2012, which equaled an effective interest rate of 2.99%. Both of these swap contracts mature in July 2017. These swap contracts have been designated as cash flow hedges.

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

For the fixed rate HollyFrontier Senior Notes and HEP Senior Notes, changes in interest rates will generally affect fair value of the debt, but not our earnings or cash flows. The outstanding principal, estimated fair value and estimated change in fair value (assuming a hypothetical 10% change in the yield-to-maturity rates) for these debt instruments as of December 31, 2012 is presented below:



	Outstanding Principal		Estimated Fair Value		Estimated Change in Fair Value
	(In thousands)
HollyFrontier Senior Notes	$	436,812	$	470,990	$	12,872
HEP Senior Notes	$	450,000	$	484,125	$	14,250

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For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2012, outstanding borrowings under the HEP Credit Agreement were $421.0 million. By means of its cash flow hedges, HEP has effectively converted the variable rate on $305.0 million of outstanding principal to a weighted average fixed rate of 3.12%.

At December 31, 2012, our marketable securities 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.

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

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

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


Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

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

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

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

Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income attributable to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants.

Set forth below is our calculation of EBITDA.



	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Net income attributable to HollyFrontier stockholders	$	1,727,172		$	1,023,397		$	103,964
Add income tax provision	1,027,962			581,991			59,312
Add interest expense	104,186			78,323			74,196
Subtract interest income	(4,786		)	(1,284		)	(1,168		)
Add depreciation and amortization	242,868			159,707			117,529
EBITDA	$	3,097,402		$	1,842,134		$	353,833

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

Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis.

Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. These two margins do not include the effect of depreciation and amortization. Each of these component performance measures can be reconciled directly to our consolidated statements of income.

Other companies in our industry may not calculate these performance measures in the same manner.

Refinery Gross and Net Operating Margins

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

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



	Years Ended December 31,
	2012			2011			2010
	(Dollars in thousands, except per barrel amounts)
Consolidated
Average sales price per produced barrel sold	$	119.48		$	118.82		$	91.06
Times sales of produced refined products sold (BPD)	431,060			332,720			228,140
Times number of days in period	366			365			365
Refined product sales from produced products sold	$	18,850,116		$	14,429,833		$	7,582,666

Total refined product sales	$	18,850,116		$	14,429,833		$	7,582,666
Add refined product sales from purchased products and rounding ⁽¹⁾	572,206			350,843			130,866
Total refined product sales	19,422,322			14,780,676			7,713,532
Add direct sales of excess crude oil ⁽²⁾	505,971			558,855			459,743
Add other refining segment revenue ⁽³⁾	114,662			52,899			113,725
Total refining segment revenue	20,042,955			15,392,430			8,287,000
Add HEP segment sales and other revenues	288,501			212,995			182,093
Add corporate and other revenues	1,048			1,098			412
Subtract consolidations and eliminations	(241,780		)	(166,995		)	(146,576		)
Sales and other revenues	$	20,090,724		$	15,439,528		$	8,322,929

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



	Years Ended December 31,
	2012			2011			2010
	(Dollars in thousands, except per barrel amounts)
Consolidated
Average cost of products per produced barrel sold	$	94.59		$	98.18		$	82.27
Times sales of produced refined products sold (BPD)	431,060			332,720			228,140
Times number of days in period	366			365			365
Cost of products for produced products sold	$	14,923,271		$	11,923,254		$	6,850,713

Total cost of products for produced products sold	$	14,923,271		$	11,923,254		$	6,850,713
Add refined product costs from purchased products and rounding ⁽¹⁾	572,755			351,788			131,668
Total cost of refined products sold	15,496,026			12,275,042			6,982,381
Add crude oil cost of direct sales of excess crude oil ⁽²⁾	492,790			550,619			454,566
Add other refining segment cost of products sold ⁽⁴⁾	90,132			18,672			73,410
Total refining segment cost of products sold	16,078,948			12,844,333			7,510,357
Subtract consolidations and eliminations	(238,305		)	(164,255		)	(143,208		)
Costs of products sold (exclusive of depreciation and amortization)	$	15,840,643		$	12,680,078		$	7,367,149

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



	Years Ended December 31,
	2012			2011			2010
	(Dollars in thousands, except per barrel amounts)
Consolidated
Average refinery operating expenses per produced barrel sold	$	5.49		$	5.36		$	5.08
Times sales of produced refined products sold (BPD)	431,060			332,720			228,140
Times number of days in period	366			365			365
Refinery operating expenses for produced products sold	$	866,146		$	650,933		$	423,017

Total refinery operating expenses per produced products sold	$	866,146		$	650,933		$	423,017
Add other refining segment operating expenses and rounding ⁽⁵⁾	37,231			35,659			26,573
Total refining segment operating expenses	903,377			686,592			449,590
Add HEP segment operating expenses	89,395			63,029			53,138
Add corporate and other costs	2,721			427			2,172
Subtract consolidations and eliminations	(527		)	(1,967		)	(486		)
Operating expenses (exclusive of depreciation and amortization)	$	994,966		$	748,081		$	504,414

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



	Years Ended December 31,
	2012			2011			2010
	(Dollars in thousands, except per barrel amounts)
Consolidated
Net operating margin per barrel	$	19.40		$	15.28		$	3.71
Add average refinery operating expenses per produced barrel	5.49			5.36			5.08
Refinery gross margin per barrel	24.89			20.64			8.79
Add average cost of products per produced barrel sold	94.59			98.18			82.27
Average sales price per produced barrel sold	$	119.48		$	118.82		$	91.06
Times sales of produced refined products sold (BPD)	431,060			332,720			228,140
Times number of days in period	366			365			365
Refined product sales from produced products sold	$	18,850,116		$	14,429,833		$	7,582,666

Total refined product sales from produced products sold	$	18,850,116		$	14,429,833		$	7,582,666
Add refined product sales from purchased products and rounding ⁽¹⁾	572,206			350,843			130,866
Total refined product sales	19,422,322			14,780,676			7,713,532
Add direct sales of excess crude oil ⁽²⁾	505,971			558,855			459,743
Add other refining segment revenue ⁽³⁾	114,662			52,899			113,725
Total refining segment revenue	20,042,955			15,392,430			8,287,000
Add HEP segment sales and other revenues	288,501			212,995			182,093
Add corporate and other revenues	1,048			1,098			412
Subtract consolidations and eliminations	(241,780		)	(166,995		)	(146,576		)
Sales and other revenues	$	20,090,724		$	15,439,528		$	8,322,929


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

(2)

We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, at times we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.


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


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


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

Table of Content


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, 2012 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, 2012, 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, 2012. That report appears on page 55.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

and Stockholders of HollyFrontier Corporation

We have audited HollyFrontier Corporation's internal control over financial reporting as of December 31, 2012, 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 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, 2012, 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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2012 and our report dated February 27, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 27, 2013

Index to Consolidated Financial Statements



	Page Reference

Report of Independent Registered Public Accounting Firm	57

Consolidated Balance Sheets at December 31, 2012 and 2011	58

Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010	59

Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	60

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	61

Consolidated Statements of Equity for the years ended December 31, 2012, 2011 and 2010	62

Notes to Consolidated Financial Statements	63

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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, the Company has elected to change its method of accounting for accounts receivables and payables with the same counterparty where a right of setoff exists from a gross presentation to a net presentation in the consolidated balance sheets.

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, 2012, 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 27, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 27, 2013

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	December 31,
	2012			2011
				As Adjusted (See Note 2)
ASSETS
Current assets:
Cash and cash equivalents (HEP: $5,237 and $6,369, respectively)	$	1,757,699		$	1,578,904
Marketable securities	630,586			211,639
Accounts receivable: Product and transportation (HEP: $38,097 and $37,290, respectively)	587,728			703,691
Crude oil resales	46,502			5,166
	634,230			708,857
Inventories: Crude oil and refined products	1,238,678			1,052,084
Materials, supplies and other (HEP: $1,259 and $1,483, respectively)	80,954			62,535
	1,319,632			1,114,619
Income taxes receivable	74,957			87,277
Prepayments and other (HEP: $2,360 and $2,246, respectively)	53,161			219,450
Total current assets	4,470,265			3,920,746

Properties, plants and equipment, at cost (HEP: $1,155,710 and $1,099,579, respectively)	3,943,114			3,631,787
Less accumulated depreciation (HEP: $(141,154) and $(93,200), respectively)	(748,414		)	(578,882		)
	3,194,700			3,052,905
Marketable securities (long-term)	5,116			50,067
Other assets: Turnaround costs	151,764			57,060
Goodwill (HEP: $288,991 and $288,991, respectively)	2,338,302			2,336,510
Intangibles and other (HEP: $76,300 and $75,902, respectively)	168,850			158,955
	2,658,916			2,552,525
Total assets	$	10,328,997		$	9,576,243

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $12,030 and $21,709, respectively)	$	1,314,151		$	1,504,694
Income taxes payable	—			40,366
Accrued liabilities (HEP: $23,705 and $16,006, respectively)	195,077			169,940
Deferred income tax liabilities	145,216			175,683
Total current liabilities	1,654,444			1,890,683

Long-term debt (HEP: $864,673 and $598,761, respectively)	1,336,238			1,214,742
Deferred income taxes	536,670			463,721
Other long-term liabilities (HEP: $28,683 and $4,000, respectively)	158,987			171,197

Equity:
HollyFrontier stockholders’ equity:
Preferred stock, $1.00 par value – 5,000,000 shares authorized; none issued	—			—
Common stock $.01 par value – 320,000,000 shares authorized; 255,962,866 shares issued as of December 31, 2012 and December 31, 2011	2,560			2,563
Additional capital	3,911,353			3,859,367
Retained earnings	3,054,769			1,964,656
Accumulated other comprehensive income (loss)	(8,425		)	77,873
Common stock held in treasury, at cost – 52,411,370 and 46,630,220 shares as of December 31, 2012 and December 31, 2011, respectively	(907,303		)	(700,449		)
Total HollyFrontier stockholders’ equity	6,052,954			5,204,010
Noncontrolling interest	589,704			631,890
Total equity	6,642,658			5,835,900
Total liabilities and equity	$	10,328,997		$	9,576,243

Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2012 and December 31, 2011. HEP is a consolidated variable interest entity.

In July 2012, HEP acquired our 75% interest in UNEV Pipeline, LLC (“UNEV”). We have recast HEP's asset and liability balances at December 31, 2011 presented parenthetically above to include balances attributable to UNEV. See Note 4.

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)



	Years Ended December 31,
	2012			2011			2010

Sales and other revenues	$	20,090,724		$	15,439,528		$	8,322,929
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	15,840,643			12,680,078			7,367,149
Operating expenses (exclusive of depreciation and amortization)	994,966			748,081			504,414
General and administrative expenses (exclusive of depreciation and amortization)	128,101			120,114			70,839
Depreciation and amortization	242,868			159,707			117,529
Total operating costs and expenses	17,206,578			13,707,980			8,059,931
Income from operations	2,884,146			1,731,548			262,998
Other income (expense):
Earnings of equity method investments	2,923			2,300			2,393
Interest income	4,786			1,284			1,168
Interest expense	(104,186		)	(78,323		)	(74,196		)
Gain on sale of marketable equity securities	326			—			—
Merger transaction costs	—			(15,114		)	—
	(96,151		)	(89,853		)	(70,635		)
Income before income taxes	2,787,995			1,641,695			192,363
Income tax provision:
Current	932,554			590,851			35,472
Deferred	95,408			(8,860		)	23,840
	1,027,962			581,991			59,312
Net income	1,760,033			1,059,704			133,051
Less net income attributable to noncontrolling interest	32,861			36,307			29,087
Net income attributable to HollyFrontier stockholders	$	1,727,172		$	1,023,397		$	103,964
Earnings per share attributable to HollyFrontier stockholders:
Basic	$	8.41		$	6.46		$	0.98
Diluted	$	8.38		$	6.42		$	0.97
Average number of common shares outstanding:
Basic	205,289			158,486			106,436
Diluted	206,184			159,294			107,218

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)



	Years Ended December 31,
	2012			2011			2010

Net income	$	1,760,033		$	1,059,704		$	133,051
Other comprehensive income (loss):
Securities available-for-sale:
Unrealized gain (loss) on available-for-sale securities	179			(530		)	114
Reclassification adjustment to net income on sale or maturity of marketable securities	(415		)	14			—
Net unrealized gain (loss) on available-for-sale securities	(236		)	(516		)	114
Unrealized gain (loss), net of reclassifications from contract settlements of hedging instruments	(191,039		)	176,936			(923		)
Pension plan curtailment	7,102			—			—
Change in minimum pension liability	(9,161		)	(71		)	(1,470		)
Change in retirement medical obligation	53,450			(3,515		)	(238		)
Other comprehensive income (loss) before income taxes	(139,884		)	172,834			(2,517		)
Income tax expense (benefit)	(54,950		)	66,138			(348		)
Other comprehensive income (loss)	(84,934		)	106,696			(2,169		)
Total comprehensive income	1,675,099			1,166,400			130,882
Less noncontrolling interest in comprehensive income	34,225			39,122			27,464
Comprehensive income attributable to HollyFrontier stockholders	$	1,640,874		$	1,127,278		$	103,418

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2012			2011			2010
				As Adjusted (See Note 2)
Cash flows from operating activities:
Net income	$	1,760,033		$	1,059,704		$	133,051
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	242,868			159,707			117,529
Earnings of equity method investments, net of distributions	701			387			482
Gain on sale of marketable equity securities	(326		)	—			—
Deferred income taxes	95,408			(8,860		)	23,840
Equity-based compensation expense	39,203			26,825			11,498
Change in fair value – derivative instruments	52,335			306			1,464
(Increase) decrease in current assets:
Accounts receivable	71,627			373,591			43,437
Inventories	(205,013		)	(56,828		)	(96,854		)
Income taxes receivable	19,056			(36,394		)	(14,990		)
Prepayments and other	(9,366		)	(14,214		)	369
Increase (decrease) in current liabilities:
Accounts payable	(194,051		)	(251,428		)	70,279
Income taxes payable	(40,366		)	72,091			—
Accrued liabilities	(39,851		)	60,467			22,414
Turnaround expenditures	(159,707		)	(32,023		)	(34,966		)
Other, net	30,136			(14,940		)	5,702
Net cash provided by operating activities	1,662,687			1,338,391			283,255

Cash flows from investing activities:
Additions to properties, plants and equipment	(290,334		)	(158,026		)	(103,722		)
Additions to properties, plants and equipment – HEP	(44,929		)	(216,215		)	(109,510		)
Increase in cash due to merger with Frontier	—			872,739			—
Investment in Sabine Biofuels	(2,000		)	(9,125		)	—
Purchases of marketable securities	(671,552		)	(561,899		)	—
Sales and maturities of marketable securities	297,711			301,020			—
Net cash provided by (used for) investing activities	(711,104		)	228,494			(213,232		)

Cash flows from financing activities:
Borrowings under credit agreement	—			—			310,000
Repayments under credit agreement	—			—			(310,000		)
Borrowings under credit agreement – HEP	587,000			118,000			66,000
Repayments under credit agreement – HEP	(366,000		)	(77,000		)	(113,000		)
Net proceeds from issuance of senior notes – HEP	294,750			—			147,540
Principal tender on senior notes	(205,000		)	(8,203		)	—
Principal tender on senior notes – HEP	(185,000		)	—			—
Proceeds from issuance of common units – HEP	—			75,815			—
Purchase of treasury stock	(209,600		)	(42,795		)	(1,368		)
Structured stock repurchase arrangement	8,620			—			—
Contribution from joint venture partner	6,000			33,500			23,500
Dividends	(658,085		)	(252,133		)	(31,868		)
Distributions to noncontrolling interest	(58,788		)	(50,874		)	(48,493		)
Excess tax benefit from equity-based compensation	23,361			1,804			(1,094		)
Purchase of units for incentive grants – HEP	(5,240		)	(1,641		)	(2,704		)
Deferred financing costs	(3,305		)	(11,815		)	(3,121		)
Other	(1,501		)	(1,740		)	(910		)
Net cash provided by (used for) financing activities	(772,788		)	(217,082		)	34,482

Cash and cash equivalents:
Increase for the period	178,795			1,349,803			104,505
Beginning of period	1,578,904			229,101			124,596
End of period	$	1,757,699		$	1,578,904		$	229,101

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	101,709		$	78,483		$	66,674
Income taxes	$	983,618		$	552,487		$	62,084

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(In thousands)



	HollyFrontier Stockholders' Equity
	Common Stock			Additional Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Non-controlling Interest			Total Equity
Balance at December 31, 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 and tax benefit on exercise of stock options	—			534			—			—			—			—			534
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		)
Distribution to noncontrolling interest holders	—			—			—			—			—			(50,874		)	(50,874		)
Other comprehensive income, net of tax	—			—			—			103,881			—			2,815			106,696
Issuance of common stock upon merger with Frontier Oil Corporation	1,037			3,704,203			—			—			—			—			3,705,240
Allocated equity on HEP common unit issuances, net of tax	—			(44,885		)	—			238			—			16,852			(27,795		)
Contribution from joint venture partner	—			—			—			—			—			36,500			36,500
Issuance of common stock under incentive compensation plans, net of forfeitures	—			(20,150		)	—			—			20,150			—			—
Equity-based compensation, net of tax benefit	—			26,584			—			—			—			2,046			28,630
Purchase of treasury stock	—			—			—			—			(42,795		)	—			(42,795		)
Other	—			—			—			—			—			(2,476		)	(2,476		)
Balance at December 31, 2011	$	2,563		$	3,859,367		$	1,964,656		$	77,873		$	(700,449	)	$	631,890		$	5,835,900
Net income	—			—			1,727,172			—			—			32,861			1,760,033
Dividends	—			—			(637,059		)	—			—			—			(637,059		)
Distributions to noncontrolling interest holders	—			—			—			—			—			(58,788		)	(58,788		)
Other comprehensive income, net of tax	—			—			—			(86,298		)	—			1,364			(84,934		)
Allocated equity on HEP common unit issuances, net of tax	—			11,469			—			—			—			(18,768		)	(7,299		)
Contribution from joint venture partner	—			—			—			—			—			3,000			3,000
Issuance of common stock under incentive compensation plans, net of forfeitures	(3		)	(27,809		)	—			—			27,812			—			—
Equity-based compensation, net of tax benefit	—			59,706			—			—			—			2,858			62,564
Purchase of treasury stock	—			—			—			—			(234,666		)	—			(234,666		)
Net proceeds received under structured share repurchase arrangement	—			8,620			—			—			—			—			8,620
Purchase of HEP units for restricted grants	—			—			—			—			—			(4,713		)	(4,713		)
Balance at December 31, 2012	$	2,560		$	3,911,353		$	3,054,769		$	(8,425	)	$	(907,303	)	$	589,704		$	6,642,658

See accompanying notes.

Table of Content

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

We merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC” (see Note 3). Accordingly, these financial statements include Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

We are principally an independent petroleum refiner that produces high-value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate petroleum refineries that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. As of December 31, 2012, 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 44% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, L.L.C. (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”) and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

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

Variable Interest 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 for the entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly impact the entity's financial performance, the obligation to absorb the entity's expected losses or rights to expected residual returns. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP's 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 upon reconsolidation in 2008 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.

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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

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

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

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 $2.5 million and $3.5 million at December 31, 2012 and 2011, respectively.

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

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

Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in our consolidated balance sheets and are measured at fair value. Changes in the derivative instrument's fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 14 for additional information.

Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value, which is generally determined under an income approach using the forecasted cash flows associated with the underlying asset. Estimates of future cash flows require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2012, 2011 and 2010.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

Our asset retirement obligations were $18.1 million and $14.4 million at December 31, 2012 and 2011, respectively, which are included in “Other long-term liabilities” in our consolidated balance sheets. Accretion expense was insignificant for the years ended December 31, 2012, 2011 and 2010.

Intangibles and Goodwill: Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized while, intangible assets with finite useful lives are amortized on a straight-line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our analysis entails a comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates minimum annual cash inflows of $24.4 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 $2.0 million. The balance of this transportation agreement was $44.5 million and $46.5 million at December 31, 2012 and 2011, respectively, and is presented net of accumulated amortization of $15.7 million and $13.7 million, respectively, in “Intangibles and other” in our consolidated balance sheets. There were no impairments of intangible assets or goodwill during the years ended December 31, 2012, 2011 and 2010.

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, 2012, HEP's underlying equity in the SLC Pipeline was $60.0 million compared to its recorded investment balance of $25.0 million, a difference of $35.0 million. This is attributable to the difference between HEP's contributed capital and its allocated equity at formation of the SLC Pipeline. This difference is being amortized as an adjustment to HEP's pro-rata share of earnings.

Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling costs incurred are reported in cost of products sold.

Depreciation: Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 20 to 25 years for refining, pipeline and terminal facilities, 10 to 40 years for buildings and improvements, 5 to 30 years for other fixed assets and 5 years for vehicles.

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

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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.


NOTE 2:	Change in Accounting Principle

In the first quarter of 2012, we changed our policy of reporting certain same-party accounts receivable and payable balances in the consolidated balance sheets to reflect a net amount due under contractual netting agreements. Prior to this change, we reported such balances on a gross basis with a same-party receivable and payable balance presented separately in our balance sheet. GAAP permits a reporting entity to elect a policy of offsetting same-party receivables and payables when such amounts are net settled under legally enforceable contractual setoff provisions. We believe that a net presentation is preferable because it more appropriately presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated with such assets and liabilities. Additionally, we believe a net presentation of such amounts conforms to the predominant practices used by other companies in our industry. We have applied this change in accounting principle on a retrospective basis and have recast our prior period financial statements.

The following table summarizes the line items affected in our consolidated balance sheet at December 31, 2011:



	As Originally Reported		As Adjusted		Effect of Change
	(In thousands)
Accounts receivable: Crude oil resales	$	743,544	$	5,166	$	(738,378	)
Total current assets	4,659,124		3,920,746		(738,378		)
Total assets	$	10,314,621	$	9,576,243	$	(738,378	)

Accounts payable	$	2,243,072	$	1,504,694	$	(738,378	)
Total current liabilities	2,629,061		1,890,683		(738,378		)
Total liabilities and equity	$	10,314,621	$	9,576,243	$	(738,378	)

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

The following table summarizes the line items affected in our consolidated statements of cash flows for the years ended December 31, 2011 and 2010:



	As Originally Reported			As Adjusted			Effect of Change
	(In thousands)
December 31, 2011
(Increase) decrease in current assets:
Accounts receivable	$	286,737		$	373,591		$	86,854

Increase (decrease) in current liabilities:
Accounts payable	$	(164,574	)	$	(251,428	)	$	(86,854	)

December 31, 2010
(Increase) decrease in current assets:
Accounts receivable	$	(228,466	)	$	43,437		$	271,903

Increase (decrease) in current liabilities:
Accounts payable	$	342,182		$	70,279		$	(271,903	)

At December 31, 2012, our accounts payable balance is presented net of $723.4 million in crude oil receivables subject to contractual setoff provisions. There was no cumulative impact to retained earnings since this change in accounting principle did not affect earnings.


NOTE 3:	Holly-Frontier Merger

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

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

Adjustments made to derive pro forma net income primarily relate to depreciation and amortization expense to reflect our new basis in the legacy Frontier refining facilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

For the year ended December 31, 2011, we 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 included $26.5 million in integration and severance costs associated with the merger integration.


NOTE 4:	Holly Energy Partners

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

As of December 31, 2012, we owned a 44% 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.

HEP has two primary customers (including us) and generates revenues by charging tariffs for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed further below), we accounted for 84% of HEP’s total revenues for the year ended December 31, 2012. We do not provide financial or equity support through any liquidity arrangements and / or debt guarantees to HEP.

HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes. With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse to our 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, 2012, we have an agreement to pledge up to 6.0 million 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 customer of HEP were to terminate its contracts or fail to meet desired shipping or throughput levels for an extended period of time, revenue would be reduced and HEP could suffer substantial losses to the extent that a new customer is not found. In the event that HEP incurs a loss, our operating results will reflect HEP’s loss, net of intercompany eliminations, to the extent of our ownership interest in HEP at that point in time.

2012 Acquisition

UNEV Interest Transaction

On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in cash and 1.0 million HEP common units. As a result of this transaction, our ownership interest in HEP increased to 44%, which includes the 2% general partner interest. We have a 10-year transportation agreement with the UNEV Pipeline expiring in 2022 that results in minimum annualized payments to UNEV of $16.9 million.

We accounted for this transaction as a business transfer between entities under common control, whereby we have retrospectively adjusted HEP financial information for all prior periods presented as if UNEV was a consolidated subsidiary of HEP since inception. This had no impact on our consolidated balances and amounts; however, it did affect certain amounts presented under the HEP segment in Note 21, “Segment Information” and Note 22, “Supplemental Guarantor/Non-Guarantor Financial Information.”

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

2011 Acquisition

Legacy Frontier Tankage and Terminal Asset Transaction

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

Transportation Agreements

HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2012, these agreements result in minimum annualized payments to HEP of $217.2 million.

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

HEP Common Unit Issuances

2012 Issuances

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

2011 Issuances

In December 2011, HEP issued 1.5 million of its common units priced at $53.50 per unit. Aggregate net proceeds of $75.8 million were used to repay a portion of the $150 million in promissory notes issued to us in connection with HEP's November 9, 2011 asset acquisition from us. This repayment to us is eliminated in our consolidated financial statements.

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

As a result of these 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.


NOTE 5:	Financial Instruments

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

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


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

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Continued


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


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

The carrying amounts and estimated fair values of our investments in marketable securities, derivative instruments and the senior notes at December 31, 2012 and December 31, 2011 were as follows:



					Fair Value by Input Level
Financial Instrument	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
			(In thousands)
December 31, 2012
Assets:
Marketable debt securities	$	635,702	$	635,702	$	—	$	635,702	$	—
Commodity price swaps	17,383		17,383		—		6,151		11,232
Total assets	$	653,085	$	653,085	$	—	$	641,853	$	11,232

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



December 31, 2011
Assets:
Equity securities	$	753	$	753	$	753	$	—	$	—
Marketable debt securities	260,953		260,953		—		260,953		—
Commodity price swaps	175,654		175,654		—		144,038		31,616
Total assets	$	437,360	$	437,360	$	753	$	404,991	$	31,616

Liabilities:
NYMEX futures contracts	$	1,252	$	1,252	$	1,252	$	—	$	—
HollyFrontier senior notes	651,262		693,979		—		693,979		—
HEP senior notes	325,860		344,350		—		344,350		—
HEP interest rate swaps	520		520		—		520		—
Total liabilities	$	978,894	$	1,040,101	$	1,252	$	1,038,849	$	—

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.

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Continued

Level 2 Financial Instruments

Investments in marketable debt securities and derivative instruments consisting of commodity price swaps and HEP's interest rate swaps are measured and recorded at fair value using Level 2 inputs. 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 swaps. The fair value of the marketable debt securities and senior notes is based on values provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input.

Level 3 Financial Instruments

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

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap contracts) for the year ended December 31, 2012:



Level 3 Financial Instruments		Year Ended December 31, 2012
	(In thousands)
Asset balance at beginning of period		$	31,616
Change in fair value:
Recognized in other comprehensive income		(120,966		)
Recognized in cost of products sold		(39,463		)
Settlement date fair value of contractual maturities:
Recognized in sales and other revenues		98,750
Recognized in cost of products sold		(3,595		)
Liability balance at end of period		$	(33,658	)

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in an estimated fair value change of approximately $5.4 million.

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Continued


NOTE 6:	Earnings Per Share

Basic earnings per share is calculated as net income attributable to HollyFrontier stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares from variable restricted and variable performance shares. The following is a reconciliation of the denominators of the basic and diluted per share computations for net income attributable to HollyFrontier stockholders:



	Years Ended December 31,
	2012		2011		2010
	(In thousands, except per share data)
Earnings attributable to HollyFrontier stockholders	$	1,727,172	$	1,023,397	$	103,964
Average number of shares of common stock outstanding	205,289		158,486		106,436
Effect of dilutive variable restricted shares andperformance share units⁽¹⁾	895		808		782
Average number of shares of common stock outstanding assuming dilution	206,184		159,294		107,218
Basic earnings per share	$	8.41	$	6.46	$	0.98
Diluted earnings per share	$	8.38	$	6.42	$	0.97

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


NOTE 7:	Stock-Based Compensation

As of December 31, 2012, we have two principal share-based compensation plans including the Frontier plan that was retained upon the July 1, 2011 merger (collectively, the “Long-Term Incentive Compensation Plan”).

The compensation cost charged against income for these plans was $36.3 million, $24.7 million and $9.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs ratably over the vesting periods.

Additionally, HEP maintains a share-based compensation plan for HEP directors and select Holly Logistic Services, L.L.C. executives and employees. Compensation cost attributable to HEP’s share-based compensation plan was $2.7 million, $2.1 million and $2.2 million for the years ended December 31, 2012, 2011 and 2010, 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 most awards vesting over a period of one to three years. Although ownership of the shares does not transfer to the recipients until 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.

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Continued

A summary of restricted stock activity and changes during the year ended December 31, 2012 is presented below:



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

Outstanding at January 1, 2012 (non-vested)	1,122,350		$	25.48
Granted	760,177		37.27
Vesting and transfer of ownership to recipients	(1,035,025	)	26.75
Forfeited	(3,975	)	33.06
Outstanding at December 31, 2012 (non-vested)	843,527		$	34.52	$	39,266

For the year ended December 31, 2012, we issued 1,035,025 shares of our common stock upon the vesting of restricted stock grants having a grant date fair value of $27.7 million. As of December 31, 2012, there was $17.4 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 1.7 years.

Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in stock upon meeting certain criteria over the service period, and generally vest over a period of three years. Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or “market performance” criteria, or both.

The fair value of performance share unit awards subject to financial performance criteria is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of December 31, 2012, estimated share payouts for outstanding non-vested performance share unit awards ranged approximately from 110% to 180%.

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

A summary of performance share unit activity and changes during the year ended December 31, 2012 is presented below:



Performance Share Units	Grants

Outstanding at January 1, 2012 (non-vested)	774,788
Granted	561,815
Vesting and transfer of ownership to recipients	(452,357	)
Forfeited	(8,672	)
Outstanding at December 31, 2012 (non-vested)	875,574

For the year ended December 31, 2012, we issued 869,231 shares of our common stock, representing a 192% payout on vested performance share units having a grant date fair value of $6.0 million. Based on the weighted-average grant date fair value of $35.38 per share, there was $26.7 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 1.8 years.

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Continued


NOTE 8:	Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio at December 31, 2012 consisted of cash, cash equivalents and investments in marketable debt securities.

We invest in highly-rated marketable debt securities 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, which are usually held until maturity. All of these instruments are classified as available-for-sale. As a result, they are reported at fair value using quoted market prices. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income. Upon sale or maturity, realized gains on our marketable debt securities are recognized as interest income. These gains are computed based on the specific identification of the underlying cost of the securities, net of unrealized gains and losses previously reported in other comprehensive income.

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



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

December 31, 2011
State and political subdivisions debt securities	$	260,879	$	74	$	—		$	260,953
Equity securities	610		143		—			753
Total marketable securities	$	261,489	$	217	$	—		$	261,706

For the years ended December 31, 2012 and 2011, we recognized $1.1 million and $0.4 million, respectively, of interest income on our marketable debt securities. Unrealized gains and losses are temporary.


NOTE 9:	Inventories

Inventory consists of the following components:



	December 31,
	2012		2011
	(In thousands)
Crude oil	$	502,978	$	400,952
Other raw materials and unfinished products⁽¹⁾	150,090		137,356
Finished products⁽²⁾	585,610		513,776
Process chemicals⁽³⁾	3,514		1,180
Repairs and maintenance supplies and other	77,440		61,355
Total inventory	$	1,319,632	$	1,114,619


(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.

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Continued

The excess of current cost over the LIFO value of inventory was $134.0 million and $378.0 million at December 31, 2012 and 2011, respectively. For the years ended December 31, 2012, 2011 and 2010, we recognized reductions of $4.2 million, $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 10:	Properties, Plants and Equipment



	December 31,
	2012			2011
	(In thousands)
Land, buildings and improvements	$	198,610		$	168,108
Refining facilities	2,261,733			2,106,900
Pipelines and terminals	1,113,080			922,866
Transportation vehicles	29,970			29,418
Other fixed assets	105,075			97,676
Construction in progress	234,646			306,819
	3,943,114			3,631,787
Accumulated depreciation	(748,414		)	(578,882		)
	$	3,194,700		$	3,052,905

We capitalized interest attributable to construction projects of $9.1 million, $17.2 million and $7.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Depreciation expense was $182.9 million, $125.0 million and $94.0 million for the years ended December 31, 2012, 2011 and 2010, respectively. For the years ended December 31, 2012, 2011 and 2010, depreciation expense included $55.5 million, $31.2 million and $26.9 million, respectively, attributable to HEP operations.


NOTE 11:	Goodwill

The following table provides a summary of changes to our goodwill balance by segment for the year ended December 31, 2012.



	Refining Segment		HEP		Total
	(In thousands)
Balance at January 1, 2012	$	2,047,519	$	288,991	$	2,336,510
Adjustment to goodwill related to Frontier merger	1,792		—		1,792
Balance at December 31, 2012	$	2,049,311	$	288,991	$	2,338,302

During the first quarter of 2012, we adjusted goodwill upon finalizing certain fair value estimates that primarily relate to income tax receivables, properties, plants and equipment and environmental liabilities that were recognized upon our July 1, 2011 merger with Frontier.

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Continued


NOTE 12:	Environmental

We expensed $46.1 million, $14.0 million and $(0.6) million for the years ended December 31, 2012, 2011 and 2010, respectively, for environmental remediation obligations. In 2012, we increased certain environmental cost accruals to reflect revisions to certain cost estimates and the timeframe for which certain environmental remediation and monitoring activities are expected to occur. The accrued environmental liability reflected in our consolidated balance sheets was $88.9 million and $42.2 million at December 31, 2012 and 2011, respectively, of which $72.6 million and $31.7 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time (up to 30 years for certain projects). They also include $15.6 million in environmental liabilities that were assumed upon our merger with Frontier in 2011.


NOTE 13:	Debt

HollyFrontier Credit Agreement

HEP Credit Agreement

HEP has a $550 million senior secured revolving credit facility that matures in June 2017 (the “HEP Credit Agreement”) and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $60 million sub-limit. At December 31, 2012, HEP was in compliance with all its covenants, had outstanding borrowings of $421.0 million and no outstanding letters of credit under the HEP Credit Agreement.

HollyFrontier Senior Notes

Our senior notes consist of the following:


•	9.875% senior notes ($286.8 million principal amount maturing June 2017)


•	6.875% senior notes ($150 million principal amount maturing November 2018)

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.

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

HollyFrontier Financing Obligation

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Continued

HEP Senior Notes

HEP’s senior notes consist of the following:


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


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

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



	December 31,
	2012			2011
	(In thousands)
9.875% Senior Notes
Principal	$	286,812		$	291,812
Unamortized discount	(7,468		)	(8,930		)
	279,344			282,882
6.875% Senior Notes
Principal	150,000			150,000
Unamortized premium	5,910			6,490
	155,910			156,490
8.5% Senior Notes
Principal	—			199,985
Unamortized premium	—			11,905
	—			211,890
Financing Obligation	36,311			37,620

Total HollyFrontier long-term debt	471,565			688,882

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Continued



	December 31,
	2012			2011
	(In thousands)
HEP Credit Agreement	421,000			200,000

HEP 8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,602		)	(1,907		)
	148,398			148,093
HEP 6.5% Senior Notes
Principal	300,000			—
Unamortized discount	(4,725		)	—
	295,275			—
HEP 6.25% Senior Notes
Principal	—			185,000
Unamortized discount	—			(8,331		)
Unamortized premium – designated fair value hedge	—			1,098
	—			177,767

Total HEP long-term debt	864,673			525,860

Total long-term debt	$	1,336,238		$	1,214,742

Principal maturities of long-term debt are as follows:



Years Ending December 31,	(In thousands)
2013	$	1,477
2014	1,666
2015	1,880
2016	2,121
2017	710,205
Thereafter	626,774
Total	$	1,344,123


NOTE 14:	Derivative Instruments and Hedging Activities

Commodity Price Risk Management


•	our inventory positions;


•	natural gas purchases;


•	costs of crude oil and related grade differentials;


•	prices of refined products; and


•	our refining margins.

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Continued

Accounting Hedges

We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas and WTI crude oil and forecasted sales of ultra-low sulfur diesel and conventional unleaded gasoline. These contracts have been designated as accounting hedges and are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to other comprehensive income. These fair value adjustments are later reclassified to earnings as the hedging instruments mature. Also on a quarterly basis, hedge ineffectiveness is measured by comparing the change in fair value of the swap contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is also recognized in earnings.

The following table presents the pre-tax effect on other comprehensive income (“OCI”) and earnings due to fair value adjustments and maturities of commodity price swaps under hedge accounting:



	Unrealized Gain (Loss) Recognized in OCI			Gain (Loss) Recognized in Earnings Due to Settlements				Gain (Loss) Attributable to Hedge Ineffectiveness Recognized in Earnings
	Unrealized Gain (Loss) Recognized in OCI			Location	Amount			Location	Amount
				(In thousands)
Year Ended December 31, 2012
Commodity price swaps
Change in fair value	$	(248,399	)	Sales and other revenues	$	(98,750	)	Sales and other revenues	$	(491	)
Loss reclassified to earnings due to settlements	55,175			Cost of products sold	43,575			Cost of products sold	(515		)
Total	$	(193,224	)		$	(55,175	)		$	(1,006	)

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

Year Ended December 31, 2010
Commodity price swaps
Change in fair value	$	(1,402	)
Loss reclassified to earnings due to settlements	1,364			Operating expenses	$	(1,364	)		$	—
Total	$	(38	)		$	(1,364	)		$	—

As of December 31, 2012, we have the following notional contract volumes related to outstanding swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas and crude oil and sales of refined products:



		Notional Contract Volumes by Year of Maturity
Commodity Price Swaps	Total Outstanding Notional	2013	2014	2015	2016	2017	Unit of Measure

Natural gas - long	96,000,000	19,200,000	19,200,000	19,200,000	19,200,000	19,200,000	MMBTU
WTI crude oil - long	12,930,000	12,565,000	365,000	—	—	—	Barrels
Ultra-low sulfur diesel - short	11,490,000	11,125,000	365,000	—	—	—	Barrels
Unleaded gasoline - short	1,440,000	1,440,000	—	—	—	—	Barrels

Economic Hedges

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

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Continued

The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges:



	Years Ended December 31,
Location of Gain Recognized in Income	2012		2011		2010
	(In thousands)
Cost of products sold	$	12,295	$	3,219	$	317
Operating expenses	573		—		—
Total	$	12,868	$	3,219	$	317

As of December 31, 2012, we have the following notional contract volumes related to our outstanding derivative contracts serving as economic hedges, all maturing in 2013:



Derivative Instrument	Total Outstanding Notional	Unit of Measure

Commodity price swap (WCS spread) - long	6,022,500	Barrels
Commodity price swap (WTI) - short	150,000	Barrels
Commodity price swap (gasoline) - short	192,000	Barrels
NYMEX futures (WTI) - long	234,000	Barrels
NYMEX futures (WTI) - short	1,091,000	Barrels
Physical contracts - long	540,000	Barrels
Physical contracts - short	540,000	Barrels

Interest Rate Risk Management

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

As of December 31, 2012, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.25% as of December 31, 2012, which equaled an effective interest rate of 3.24%. This swap matures in February 2016. HEP has two additional interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.25% as of December 31, 2012, which equaled an effective interest rate of 2.99%. Both of these swap contracts mature in July 2017. All of these swap contracts have been designated as cash flow hedges. To date, there has been no ineffectiveness on these cash flow hedges.

At December 31, 2012, HEP had a pre-tax unrealized loss recorded in accumulated other comprehensive income of $4.3 million that relates to its current and previous cash flow hedging instruments. Of this amount, $0.8 million relates to a 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.

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Continued

The following table presents the pre-tax effect on other comprehensive income and earnings due to fair value adjustments and maturities of HEP's interest rate swaps under cash flow hedge accounting:



	Unrealized Gain (Loss) Recognized in OCI			Loss Recognized in Earnings Due to Settlements
	Unrealized Gain (Loss) Recognized in OCI			Location	Amount
				(In thousands)
Year Ended December 31, 2012
Interest rate swaps
Change in fair value	$	(4,418	)
Loss reclassified to earnings due to settlements	6,603			Interest expense	$	(6,603	)
Total	$	2,185			$	(6,603	)

Year Ended December 31, 2011
Interest rate swaps
Change in fair value	$	(1,915	)
Loss reclassified to earnings due to settlements	5,477			Interest expense	$	(5,477	)
Total	$	3,562			$	(5,477	)

Year Ended December 31, 2010
Interest rate swaps
Change in fair value	$	(7,596	)
Loss reclassified to earnings due to settlements	6,711			Interest expense	$	(6,711	)
Total	$	(885	)		$	(6,711	)

The following table presents balance sheet locations and fair values of our outstanding derivative instruments. These amounts are presented on a gross basis 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.



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In thousands)
December 31, 2012
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts	Accrued liabilities	$	17,383	Accrued liabilities	$	28,054
				Other long-term liabilities	9,774
Variable-to-fixed interest rate swap contracts				Other long-term liabilities	3,430
Total		$	17,383		$	41,258

Derivatives not designated as hedging instruments:
Commodity price swap contracts				Accrued liabilities	$	51,717
Total					$	51,717

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Continued



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In thousands)
December 31, 2011
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts	Prepayments and other current assets	$	173,784
Variable-to-fixed interest rate swap contracts				Other long-term liabilities	$	520
Total		$	173,784		$	520

Derivatives not designated as hedging instruments:
Commodity price swap contracts	Prepayments and other current assets	$	1,870	Accrued liabilities	$	1,252

At December 31, 2012, we had a pre-tax net unrealized loss of $23.3 million classified in accumulated other comprehensive income that relates to all accounting hedges. Assuming commodity prices and interest rates remain unchanged, an unrealized loss of approximately $11.7 million will be effectively transferred from accumulated other comprehensive income into the statement of income as the hedging instruments mature over the next twelve-month period.


NOTE 15:	Income Taxes

The provision for income taxes is comprised of the following:



	Years Ended December 31,
	2012		2011			2010
	(In thousands)
Current
Federal	$	797,406	$	499,535		$	30,999
State	135,148		91,316			4,473
Deferred
Federal	70,671		(9,679		)	21,796
State	24,737		819			2,044
	$	1,027,962	$	581,991		$	59,312

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



	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Tax computed at statutory rate	$	975,798		$	574,682		$	67,327
State income taxes, net of federal tax benefit	110,739			64,284			4,372
Domestic production activities deduction	(54,745		)	(32,194		)	(940		)
Noncontrolling interest in net income	(12,783		)	(14,221		)	(11,315		)
Uncertain tax positions	7,309			(12,125		)	—
Other	1,644			1,565			(132		)
	$	1,027,962		$	581,991		$	59,312

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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, 2012 and 2011 are as follows:



	December 31, 2012
	Assets		Liabilities			Total
	(In thousands)
Deferred income taxes
Accrued employee benefits	$	13,285	$	—		$	13,285
Accrued post-retirement benefits	—		(563		)	(563		)
Accrued environmental costs	5,096		—			5,096
Hedging instruments	23,927		—			23,927
Inventory differences	—		(181,634		)	(181,634		)
Prepayments and other	—		(5,327		)	(5,327		)
Total current	42,308		(187,524		)	(145,216		)
Properties, plants and equipment (due primarily to tax in excess of book depreciation)	—		(539,338		)	(539,338		)
Accrued post-retirement benefits	15,628		—			15,628
Accrued environmental costs	18,963		—			18,963
Hedging instruments	3,802		—			3,802
Deferred turnaround costs	—		(60,167		)	(60,167		)
Net operating loss and tax credit carryforwards	21,863		—			21,863
Investment in HEP	—		(15,915		)	(15,915		)
Debt fair value premiums	8,820		—			8,820
Contingent liabilities	2,908		—			2,908
Other	6,766		—			6,766
Total noncurrent	78,750		(615,420		)	(536,670		)
Total	$	121,058	$	(802,944	)	$	(681,886	)



	December 31, 2011
	Assets		Liabilities			Total
	(In thousands)
Deferred income taxes
Accrued employee benefits	$	22,791	$	—		$	22,791
Accrued post-retirement 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 post-retirement 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	)

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Continued

At December 31, 2012, we had a net operating loss carryforward of $46.5 million in the state of Colorado that is scheduled to be utilized in 2013 through 2029 and a Kansas income tax credit of $15.8 million that is scheduled to be utilized in 2013 through 2019. These amounts are reflected in other current and non-current deferred tax assets.

As of December 31, 2012, the total amount of unrecognized tax benefits was $12.6 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Balance at January 1	$	2,425		$	1,864		$	1,964
Additions due to merger with Frontier	—			22,577			—
Additions for tax positions of prior years	10,305			73			6
Reductions for tax positions of prior years	(89		)	(204		)	(106		)
Settlements	—			(21,679		)	—
Reductions for statute limitations	—			(206		)	—
Balance at December 31	$	12,641		$	2,425		$	1,864

At December 31, 2012, 2011 and 2010, there are $10.2 million, $2.2 million and $1.1 million, respectively, of unrecognized tax benefits that, if recognized, would affect our effective tax rate. Unrecognized tax benefits are adjusted in the period in which new information about a tax position becomes available or the final outcome differs from the amount recorded.

We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties. We expect that unrecognized tax benefits for tax positions taken with respect to 2012 and prior years will change within the next 12 months and the majority of these items will be settled with taxing authorities.

We are subject to U.S. federal income tax, Oklahoma, New Mexico, Kansas, Utah, Arizona, Colorado and Iowa income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for tax years through December 31, 2005. In late 2010, the Internal Revenue Service commenced an examination of our U.S. federal tax returns for tax years ended December 31, 2006, 2007, 2008 and 2009. We anticipate that these audits will be completed in 2013.


NOTE 16:	Stockholders' Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2012, 2011 and 2010 are presented below:



	Years Ended December 31,
	2012		2011		2010
	(In thousands)
Common shares outstanding at January 1	209,332,646		106,529,376		106,132,538
Common shares issued in connection with merger with Frontier	—		103,270,002		—
Issuance of common shares upon exercise of stock options	—		—		80,400
Issuance of restricted stock, excluding restricted stock with performance feature	691,207		512,880		282,886
Vesting of performance units	869,231		233,134		140,286
Vesting of restricted stock with performance feature	146,400		124,332		12,300
Forfeitures of restricted stock	(3,975	)	(3,730	)	(30,084	)
Purchase of treasury stock ⁽¹⁾	(7,484,013	)	(1,333,348	)	(88,950	)
Common shares outstanding at December 31	203,551,496		209,332,646		106,529,376


(1)	Includes 560,484, 747,225 and 88,950 shares, respectively, withheld under the terms of stock-based compensation agreements to provide funds for the payment of payroll and income taxes due at the vesting of share-based awards.

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Continued

In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. These programs may be discontinued at any time by the Board of Directors. As of December 31, 2012, we have repurchased 6,775,729 shares at a cost of $205.6 million under these stock repurchase programs.

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

During the years ended December 31, 2012, 2011 and 2010, we withheld shares of our common stock from certain employees in the amounts of $22.4 million, $24.9 million and $1.2 million, respectively. These withholdings were made under the terms of restricted stock and performance share unit agreements, and we concurrently made cash payments to fund 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 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.


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, 2012
Unrealized loss, net of reclassifications from sale or maturity, on available-for-sale securities	$	(236	)	$	(95	)	$	(141	)
Unrealized loss on hedging activities	(191,039		)	(74,846		)	(116,193		)
Pension plan curtailment	7,102			2,763			4,339
Change in minimum pension liability	(9,161		)	(3,564		)	(5,597		)
Retirement medical plan amendment	53,450			20,792			32,658
Other comprehensive loss	(139,884		)	(54,950		)	(84,934		)
Less other comprehensive income attributable to noncontrolling interest	1,364			—			1,364
Other comprehensive loss attributable to HollyFrontier stockholders	$	(141,248	)	$	(54,950	)	$	(86,298	)

Year Ended December 31, 2011
Unrealized loss on available-for-sale securities	$	(516	)	$	(199	)	$	(317	)
Unrealized gain on hedging activities	176,936			67,732			109,204
Change in minimum pension liability	(71		)	(28		)	(43		)
Change in retirement medical obligation	(3,515		)	(1,367		)	(2,148		)
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		)
Change in minimum pension liability	(1,470		)	(572		)	(898		)
Change in retirement medical obligation	(238		)	(93		)	(145		)
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	)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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



	December 31,
	2012			2011
	(In thousands)
Pension obligation	$	(23,973	)	$	(22,715	)
Retirement medical obligation	28,605			(4,042		)
Unrealized gain (loss) on available-for-sale securities	(7		)	134
Unrealized gain (loss) on hedging instruments, net of noncontrolling interest	(13,050		)	104,496
Accumulated other comprehensive income (loss)	$	(8,425	)	$	77,873


NOTE 18:	Retirement Plan

We sponsor a non-contributory defined benefit retirement plan that covers most legacy Holly non-union employees hired prior to January 1, 2007 and union employees hired prior to July 1, 2010, and was closed to new entrants effective January 1, 2007 for non-union employees and July 1, 2010 for union employees. Effective January 1, 2012, we ceased to accrue additional benefits under this plan for non-union employee participants, and effective May 1, 2012, we ceased to accrue additional benefits for union employee participants, at which time the plan was fully frozen. The changes for union employee participants have been accounted for as a curtailment. Accordingly, we adjusted the projected benefit obligation and accumulated other comprehensive income by $7.1 million and recorded additional pension expense of $0.7 million in the second quarter of 2012. The changes related to the non-union employees were also accounted for as a curtailment, which was recorded in the fourth quarter of 2011. 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.

In 2012, our Compensation Committee, pursuant to authority delegated to it by the Board of Directors, approved the termination of the HollyFrontier Corporation Pension Plan (the “Plan”). Accordingly, our remaining liability under the Plan is expected to be funded in 2013. Our actual obligations under the Plan are contingent upon the timing of the pension plan termination as well as participant settlement obligations. We expect to record an additional expense on termination of the Plan at the date we are released from the liability, including the amount of actuarial loss currently recorded as accumulated other comprehensive income ($37.6 million, $23.0 million after-tax) at December 31, 2012 plus an amount equal to any contribution we make to the Plan in excess of the $17.7 million accrued pension liability we have recorded at December 31, 2012.

The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2012 and 2011:



	Years Ended December 31,
	2012			2011
	(In thousands)
Change in plan's benefit obligation
Pension plan's benefit obligation - beginning of year	$	93,378		$	94,083
Service cost	679			5,070
Interest cost	3,962			5,125
Benefits paid	(1,379		)	(1,347		)
Actuarial loss	13,203			16,108
Settlements paid	(7,256		)	(10,510		)
Curtailment	(7,102		)	(15,151		)
Pension plan's benefit obligation - end of year	$	95,485		$	93,378

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Continued



	Years Ended December 31,
	2012			2011
	(In thousands)
Change in pension plan assets
Fair value of plan assets - beginning of year	$	61,398		$	64,490
Actual return on plan assets	2,615			(1,235		)
Benefits paid	(1,379		)	(1,347		)
Employer contributions	22,379			10,000
Settlements paid	(7,256		)	(10,510		)
Fair value of plan assets - end of year	$	77,757		$	61,398

Funded status
Under-funded balance	$	(17,728	)	$	(31,980	)

Amounts recognized in consolidated balance sheets
Accrued pension liability	$	(17,728	)	$	(31,980	)

Amounts recognized in accumulated other comprehensive loss
Cumulative actuarial loss	$	(37,589	)	$	(35,094	)
Prior service cost	—			(966		)
Total	$	(37,589	)	$	(36,060	)

The accumulated benefit obligation was $95.5 million and $86.1 million at December 31, 2012 and 2011, respectively. The measurement dates used for our retirement plan were December 31, 2012 and 2011.

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



	December 31,
	2012		2011

Discount rate	3.95	%	4.60	%
Rate of future compensation increases	N/A		4.00	%

Net periodic pension expense consisted of the following components:



	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Service cost – benefit earned during the year	$	679		$	5,070		$	4,595
Interest cost on projected benefit obligations	3,962			5,125			5,154
Expected return on plan assets	(3,798		)	(5,230		)	(4,576		)
Amortization of prior service cost	67			390			390
Amortization of net loss	1,933			2,126			2,196
Effect of settlements	2,855			3,951			—
Effect of curtailment	899			1,065			—
Net periodic pension expense	$	6,597		$	12,497		$	7,759

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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



	December 31,
	2012		2011		2010

Discount rate	4.60	%	5.65	%	6.20	%
Rate of future compensation increases	4.00	%	4.00	%	4.00	%
Expected long-term rate of return on assets	6.50	%	8.00	%	8.50	%

The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2013 are as follows:



	(In thousands)

Actuarial loss	$	2,771
Prior service cost	—
Total	$	2,771

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



	Target Allocation		Percentage of Plan Assets at December31,
Asset Category	2013		2012		2011

Cash and cash equivalents	100	%	93	%	—	%
Debt securities	—	%	—	%	62	%
Equity securities	—	%	—	%	30	%
Alternative investments	—	%	7	%	8	%
Total	100	%	100	%	100	%

The investment policy developed for 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 Plan’s primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation. Due to the expected termination of the Plan, the current target asset allocation is 100% cash and cash equivalents. The overall expected long-term rate of return on Plan assets at December 31, 2012 is 0.25% and is based on estimated returns for cash and cash equivalents, a Level 1 input. See Note 5, Financial Instruments, for information on Level inputs.

In 2012, we established a program for plan participants whose benefits pursuant to the defined benefit plan were frozen. The program provides for payments after year-end for each of the next three years provided the employee remains with us. The payments are based on each employee's years of service and eligible salary. For the year ended December 31, 2012, we recognized transition benefit costs of $15.6 million associated with transition to the new defined contribution plan.

Retirement Restoration Plan

We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. Effective January 1, 2012, we ceased to accrue benefits under this plan. We expensed $0.3 million, $0.6 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $7.4 million and $6.7 million at December 31, 2012 and 2011, respectively. As of December 31, 2012, the projected benefit obligation under this plan was $7.4 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.7 million in 2013; $2.2 million in 2014; $0.5 million in 2015; $0.5 million in 2016; $1.5 million in 2017; and $1.4 million in 2018 through 2022.

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 $16.0 million, $9.7 million and $5.5 million for the years ended December 31, 2012, 2011 and 2010, respectively, in connection with these plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

Post-retirement Healthcare Plans

We provide post-retirement medical benefits to certain eligible employees. These plans are unfunded and provide differing levels of healthcare benefits dependent upon hire date and work location. Not all of our employees are covered by these plans at December 31, 2012.

Effective December 31, 2012, we amended the post-retirement healthcare plans for participants retiring after December 31, 2012 by eliminating post-retirement benefits after reaching age 65 and eliminating early retirement benefits for most participants who retire before reaching age 62. In addition, certain future retirees will receive a cash payment in lieu of post-retirement benefits after reaching age 65 and other changes were made generally to conform benefits. We expect to pay $8.3 million during 2013 to participants meeting certain requirements to receive a retiree medical transition payment.

The following table sets forth the changes in the benefit obligation and plan assets of our post-retirement healthcare plans for the years ended December 31, 2012 and 2011:



	Years Ended December 31,
	2012			2011
	(In thousands)
Change in plans' benefit obligation
Post-retirement plans' benefit obligation - beginning of year	$	77,303		$	7,862
Service cost	1,892			1,569
Interest cost	3,519			2,193
Participant contributions	760			460
Amendments	(49,399		)	(5,387		)
Plan benefits paid	(1,275		)	(1,105		)
Plan combinations	—			62,632
Actuarial (gain) loss	(6,003		)	9,079
Post-retirement plans' benefit obligation - end of year	$	26,797		$	77,303

Change in plan assets
Fair value of plan assets - beginning of year	$	—		$	—
Employer contributions	515			645
Participant contributions	760			460
Benefits paid	(1,275		)	$	(1,105	)
Fair value of plan assets - end of year	$	—		$	—

Funded status
Under-funded balance	$	(26,797	)	$	(77,303	)

Amounts recognized in consolidated balance sheets
Accrued post-retirement liability	$	(26,797	)	$	(77,303	)

Amounts recognized in accumulated other comprehensive loss
Actuarial loss	$	5,359		$	11,631
Transition obligation	—			—
Prior service cost	(52,174		)	(4,997		)
Total	$	(46,815	)	$	6,634

The accumulated benefit obligation was $26.8 million and $77.3 million at December 31, 2012 and 2011, respectively. The measurement dates used for our post-retirement healthcare plans were December 31, 2012 and 2011. Benefit payments, which reflect expected future service, are expected to be paid as follows: $9.7 million in 2013; $1.4 million in 2014; $1.3 million in 2015; $1.3 million in 2016; $1.3 million in 2017; and $7.5 million in 2018 through 2022.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued

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



	December 31,
	2012		2011

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

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



	Years Ended December 31,
	2012			2011		2010
	(In thousands)
Service cost – benefit earned during the year	$	1,892		$	1,569	$	926
Interest cost on projected benefit obligations	3,519			2,193		351
Amortization of transition obligation	—			44		44
Amortization of prior service cost (credit)	(2,221		)	—		—
Amortization of net loss	269			114		98
Net periodic pension expense	$	3,459		$	3,920	$	1,419

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



	Years Ended December 31,
	2012		2011		2010

Discount rate	4.60	%	5.75	%	5.50	%
Current health care trend rate	8.40	%	8.70	%	9.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year rate reaches ultimate trend rate			2023		2023

The effect of a 1% change in health care cost trend rates is as follows:



	1% Point Increase		1% Point Decrease
	(In thousands)
Service cost	$	506	$	(377	)
Interest cost	$	778	$	(548	)
Year-end accumulated post-retirement benefit obligation	$	1,745	$	(1,461	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


NOTE 19:	Lease Commitments

We lease certain office and storage facilities, railcars and other equipment under long-term operating leases, most of which contain renewal options. At December 31, 2012, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows:



	(In thousands)
2013	$	29,228
2014	27,119
2015	20,044
2016	16,345
2017	11,754
Thereafter	9,765
Total	$	114,255

Rental expense charged to operations was $42.6 million, $35.9 million and $22.5 million for the years ended December 31, 2012, 2011 and 2010, respectively. For the years ended December 31, 2012, 2011 and 2010, rental expense included $8.1 million, $7.4 million and $7.1 million attributable to the HEP operations.


NOTE 20:	Contingencies and Contractual Commitments

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

Contractual Commitments

We have various long-term agreements (entered in the normal course of business) to purchase crude oil, natural gas, feedstocks and other resources to ensure we have adequate supplies to operate our refineries. The substantial majority of our purchase obligations are based on market prices or rates. These contracts expire in 2014 through 2024.

We also have long-term agreements with third parties for the transportation and storage of crude oil, natural gas and feedstocks to our refineries and for terminal and storage services that expire in 2013 through 2024. At December 31, 2012, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:



	(In thousands)
2013	$	83,515
2014	83,931
2015	78,211
2016	64,128
2017	54,536
Thereafter	107,567
Total	$	471,888

These amounts do not include contractual commitments under our long-term transportation agreements with HEP. HEP is a consolidated VIE; all transactions with HEP are eliminated in these consolidated financial statements.

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


NOTE 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. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.

The Refining segment represents the operations of the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt (aggregated as a reportable segment). Refining activities involve the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel. These petroleum products are primarily marketed in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refineries that are marketed throughout North America and are distributed in Central and South America. NK Asphalt operates various asphalt terminals in Arizona and New Mexico.

The HEP segment includes all of the operations of HEP, a consolidated VIE, which owns and operates logistics assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. The HEP segment also includes a 75% interest in UNEV (a consolidated subsidiary of HEP) and a 25% interest in the SLC Pipeline. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations. 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).



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

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

Year Ended December 31, 2010
Sales and other revenues	$	8,287,000	$	182,093	$	412		$	(146,576	)	$	8,322,929
Depreciation and amortization	$	84,587	$	28,949	$	4,675		$	(682	)	$	117,529
Income (loss) from operations	$	242,466	$	92,287	$	(69,555	)	$	(2,200	)	$	262,998
Capital expenditures	$	102,034	$	109,510	$	1,688		$	—		$	213,232

(1) The Refining segment reflects the operations of the El Dorado and Cheyenne Refineries beginning July 1, 2011 (date of Holly-Frontier merger).

(2) HEP acquired our 75% interest in UNEV in July 2012. As a result, we have recast our HEP segment information to include the UNEV Pipeline operations as a consolidated subsidiary of HEP for all periods presented. The UNEV Pipeline was previously presented under Corporate and Other.

HEP segment revenues from external customers were $47.6 million, $46.4 million and $36.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


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 44% ownership interest at December 31, 2012, and its subsidiaries (collectively, “Non-Guarantor Non-Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed these obligations.

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

HEP acquired our 75% interest in UNEV in July 2012. As a result, we have recast our HEP segment information to include the UNEV Pipeline operations as a consolidated subsidiary of HEP for all periods presented. The UNEV Pipeline was previously presented as a Non-Guarantor Restricted Subsidiary.



Condensed Consolidating Balance Sheet
December 31, 2012	Parent			Guarantor Restricted Subsidiaries		Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP		Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,748,808		$	3,652	$	2		$	—		$	1,752,462	$	5,237	$	—		$	1,757,699
Marketable securities	630,579			7		—			—			630,586		—		—			630,586
Accounts receivable, net	4,788			627,262		—			—			632,050		38,097		(35,917		)	634,230
Intercompany accounts receivable (payable)	(546,655		)	285,291		261,364			—			—		—		—			—
Inventories	—			1,318,373		—			—			1,318,373		1,259		—			1,319,632
Income taxes receivable	74,957			—		—			—			74,957		—		—			74,957
Prepayments and other	21,867			34,667		—			—			56,534		2,360		(5,733		)	53,161
Total current assets	1,934,344			2,269,252		261,366			—			4,464,962		46,953		(41,650		)	4,470,265
Properties, plants and equip, net	24,209			2,444,398		—			—			2,468,607		1,014,556		(288,463		)	3,194,700
Marketable securities (long-term)	5,116			—		—			—			5,116		—		—			5,116
Investment in subsidiaries	5,251,396			74,120		—			(5,325,516		)	—		—		—			—
Intangibles and other assets	11,825			2,284,329		25,000			(25,000		)	2,296,154		365,291		(2,529		)	2,658,916
Total assets	$	7,226,890		$	7,072,099	$	286,366		$	(5,350,516	)	$	9,234,839	$	1,426,800	$	(332,642	)	$	10,328,997

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,941		$	1,336,097	$	—		$	—		$	1,338,038	$	12,030	$	(35,917	)	$	1,314,151
Income taxes payable	—			—		—			—			—		—		—			—
Accrued liabilities	71,226			105,298		581			—			177,105		23,705		(5,733		)	195,077
Deferred income tax liabilities	145,225			—		(9		)	—			145,216		—		—			145,216
Total current liabilities	218,392			1,441,395		572			—			1,660,359		35,735		(41,650		)	1,654,444
Long-term debt	460,254			36,311		—			(25,000		)	471,565		864,673		—			1,336,238
Liability to HEP	—			257,777					—			257,777		—		(257,777		)	—
Deferred income tax liabilities	530,544			—		1,175			—			531,719		—		4,951			536,670
Other long-term liabilities	48,757			85,220		—			—			133,977		28,683		(3,673		)	158,987
Investment in HEP	—			—		210,499			—			210,499		—		(210,499		)	—
Equity – HollyFrontier	5,968,943			5,251,396		74,120			(5,325,516		)	5,968,943		382,207		(298,196		)	6,052,954
Equity – noncontrolling interest	—			—		—			—			—		115,502		474,202			589,704
Total liabilities and equity	$	7,226,890		$	7,072,099	$	286,366		$	(5,350,516	)	$	9,234,839	$	1,426,800	$	(332,642	)	$	10,328,997

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Balance Sheet
December 31, 2011⁽¹⁾	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	)	$	2	$	—		$	1,572,535	$	6,369	$	—		$	1,578,904
Marketable securities	210,886			753			—		—			211,639		—		—			211,639
Accounts receivable, net	8,317			698,911			—		—			707,228		37,290		(35,661		)	708,857
Intercompany accounts receivable (payable)	(629,712		)	331,431			298,281		—			—		—		—			—
Inventories	—			1,113,136			—		—			1,113,136		1,483		—			1,114,619
Income taxes receivable	87,277			—			—		—			87,277		—		—			87,277
Prepayments and other	19,379			202,428			4		—			221,811		2,246		(4,607		)	219,450
Total current assets	1,272,038			2,343,301			298,287		—			3,913,626		47,388		(40,268		)	3,920,746
Properties, plants and equip, net	26,702			2,322,645			—		—			2,349,347		1,006,379		(302,821		)	3,052,905
Marketable securities (long-term)	50,067			—			—		—			50,067		—		—			50,067
Investment in subsidiaries	5,280,403			331,413			35,511		(5,611,816		)	35,511		—		(35,511		)	—
Intangibles and other assets	19,329			2,242,197			—		—			2,261,526		364,893		(73,894		)	2,552,525
Total assets	$	6,648,539		$	7,239,556		$	333,798	$	(5,611,816	)	$	8,610,077	$	1,418,660	$	(452,494	)	$	9,576,243

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	23,497		$	1,494,790		$	359	$	—		$	1,518,646	$	21,709	$	(35,661	)	$	1,504,694
Income taxes payable	40,366			—			—		—			40,366		—		—			40,366
Accrued liabilities	53,390			103,981			1,170		—			158,541		16,006		(4,607		)	169,940
Deferred income tax liabilities	175,683			—			—		—			175,683		—		—			175,683
Total current liabilities	292,936			1,598,771			1,529		—			1,893,236		37,715		(40,268		)	1,890,683
Long-term debt	651,261			37,620			—		—			688,881		598,761		(72,900		)	1,214,742
Liability to HEP	—			269,870			—		—			269,870		—		(269,870		)	—
Deferred income tax liabilities	457,914			—			856		—			458,770		—		4,951			463,721
Other long-term liabilities	116,443			52,892			—		—			169,335		4,000		(2,138		)	171,197
Equity – HollyFrontier	5,129,985			5,280,403			331,413		(5,611,816		)	5,129,985		679,182		(605,157		)	5,204,010
Equity – noncontrolling interest	—			—			—		—			—		99,002		532,888			631,890
Total liabilities and equity	$	6,648,539		$	7,239,556		$	333,798	$	(5,611,816	)	$	8,610,077	$	1,418,660	$	(452,494	)	$	9,576,243

(1) Certain amounts have been revised to conform to our current year presentation in the Parent, Guarantor Restricted Subsidiary, Non-Guarantor Restricted Subsidiary and Elimination columns.

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries		Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	494		$	20,043,335		$	174	$	—		$	20,044,003		$	288,501		$	(241,780	)	$	20,090,724
Operating costs and expenses:
Cost of products sold	—			16,078,948			—		—			16,078,948			—			(238,305		)	15,840,643
Operating expenses	—			906,098			—		—			906,098			89,395			(527		)	994,966
General and administrative	118,860			1,519			128		—			120,507			7,594			—			128,101
Depreciation and amortization	4,172			181,735			—		—			185,907			57,789			(828		)	242,868
Total operating costs and expenses	123,032			17,168,300			128		—			17,291,460			154,778			(239,660		)	17,206,578
Income (loss) from operations	(122,538		)	2,875,035			46		—			2,752,543			133,723			(2,120		)	2,884,146
Other income (expense):
Earnings of equity method investments	2,921,077			49,347			49,066		(2,970,865		)	48,625			3,364			(49,066		)	2,923
Interest income (expense)	(41,564		)	(3,631		)	676		—			(44,519		)	(57,219		)	2,338			(99,400		)
Gain on sale of marketable securities	—			326			—		—			326			—			—			326
	2,879,513			46,042			49,742		(2,970,865		)	4,432			(53,855		)	(46,728		)	(96,151		)
Income before income taxes	2,756,975			2,921,077			49,788		(2,970,865		)	2,756,975			79,868			(48,848		)	2,787,995
Income tax provision	1,027,591			—			—		—			1,027,591			371			—			1,027,962
Net income	1,729,384			2,921,077			49,788		(2,970,865		)	1,729,384			79,497			(48,848		)	1,760,033
Less net income attributable to noncontrolling interest	—			—			—		—			—			32,861			—			32,861
Net income attributable to HollyFrontier stockholders	$	1,729,384		$	2,921,077		$	49,788	$	(2,970,865	)	$	1,729,384		$	46,636		$	(48,848	)	$	1,727,172
Comprehensive income attributable to HollyFrontier stockholders	$	1,835,488		$	2,727,854		$	49,788	$	(2,970,865	)	$	1,642,265		$	47,457		$	(48,848	)	$	1,640,874



Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	1,008		$	15,392,446		$	74		$	—		$	15,393,528		$	212,995		$	(166,995	)	$	15,439,528
Operating costs and expenses:
Cost of products sold	—			12,844,333			—			—			12,844,333			—			(164,255		)	12,680,078
Operating expenses	—			687,381			(362		)	—			687,019			63,029			(1,967		)	748,081
General and administrative	111,093			2,445			—			—			113,538			6,576			—			120,114
Depreciation and amortization	4,165			123,082			—			—			127,247			33,288			(828		)	159,707
Total operating costs and expenses	115,258			13,657,241			(362		)	—			13,772,137			102,893			(167,050		)	13,707,980
Income (loss) from operations	(114,250		)	1,735,205			436			—			1,621,391			110,102			55			1,731,548
Other income (expense):
Earnings of equity method investments	1,771,022			38,546			38,308			(1,809,820		)	38,056			2,552			(38,308		)	2,300
Interest income (expense)	(38,619		)	(2,729		)	54			—			(41,294		)	(38,209		)	2,464			(77,039		)
Merger transaction costs	(15,114		)	—			—			—			(15,114		)	—			—			(15,114		)
	1,717,289			35,817			38,362			(1,809,820		)	(18,352		)	(35,657		)	(35,844		)	(89,853		)
Income before income taxes	1,603,039			1,771,022			38,798			(1,809,820		)	1,603,039			74,445			(35,789		)	1,641,695
Income tax provision	581,757			—			—			—			581,757			234			—			581,991
Net income	1,021,282			1,771,022			38,798			(1,809,820		)	1,021,282			74,211			(35,789		)	1,059,704
Less net income attributable to noncontrolling interest	—			—			—			—			—			36,307			—			36,307
Net income attributable to HollyFrontier stockholders	$	1,021,282		$	1,771,022		$	38,798		$	(1,809,820	)	$	1,021,282		$	37,904		$	(35,789	)	$	1,023,397
Comprehensive income attributable to HollyFrontier stockholders	$	1,018,650		$	1,876,788		$	38,798		$	(1,809,820	)	$	1,124,416		$	38,651		$	(35,789	)	$	1,127,278

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Income and Comprehensive 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		$	—		$	—		$	8,287,412		$	182,093		$	(146,576	)	$	8,322,929
Operating costs and expenses:
Cost of products sold	—			7,510,357			—			—			7,510,357			—			(143,208		)	7,367,149
Operating expenses	2,411			449,349			2			—			451,762			53,138			(486		)	504,414
General and administrative	62,130			990			—			—			63,120			7,719			—			70,839
Depreciation and amortization	3,745			85,517			—			—			89,262			28,949			(682		)	117,529
Total operating costs and expenses	68,286			8,046,213			2			—			8,114,501			89,806			(144,376		)	8,059,931
Income (loss) from operations	(67,874		)	240,787			(2		)	—			172,911			92,287			(2,200		)	262,998
Other income (expense):
Earnings of equity method investments	265,367			30,036			29,998			(295,403		)	29,998			2,393			(29,998		)	2,393
Interest income (expense)	(33,838		)	(5,456		)	40			—			(39,254		)	(36,240		)	2,466			(73,028		)
	231,529			24,580			30,038			(295,403		)	(9,256		)	(33,847		)	(27,532		)	(70,635		)
Income before income taxes	163,655			265,367			30,036			(295,403		)	163,655			58,440			(29,732		)	192,363
Income tax provision	59,016			—			—			—			59,016			296			—			59,312
Net income	104,639			265,367			30,036			(295,403		)	104,639			58,144			(29,732		)	133,051
Less net income attributable to noncontrolling interest	—			—			—			—			—			29,087			—			29,087
Net income attributable to HollyFrontier stockholders	$	104,639		$	265,367		$	30,036		$	(295,403	)	$	104,639		$	29,057		$	(29,732	)	$	103,964
Comprehensive income attributable to HollyFrontier stockholders	$	103,279		$	265,443		$	30,036		$	(295,403	)	$	103,355		$	29,795		$	(29,732	)	$	103,418

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			HollyFrontier Corp. Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	1,596,358		$	(33,004	)	$	1,286		$	1,564,640		$	162,036		$	(63,989	)	$	1,662,687

Cash flows from investing activities
Additions to properties, plants and equip	(7,965		)	(282,369		)	—			(290,334		)	—			—			(290,334		)
Additions to properties, plants and equip – HEP	—			—			—			—			(44,929		)	—			(44,929		)
Investment in Sabine Biofuels	—			(2,000		)	—			(2,000		)	—			—			(2,000		)
Purchases of marketable securities	(671,552		)	—			—			(671,552		)	—			—			(671,552		)
Sales and maturities of marketable securities	296,780			931			—			297,711			—			—			297,711
	(382,737		)	(283,438		)	—			(666,175		)	(44,929		)	—			(711,104		)
Cash flows from financing activities
Net borrowings under credit agreement – HEP	—			—			—			—			221,000			—			221,000
Repayment of promissory notes	—			72,900			—			72,900			(72,900		)	—			—
Net proceeds from issuance of senior notes - HEP	—			—			—			—			294,750			—			294,750
Principal tender on senior notes	(205,000		)	—			—			(205,000		)	—			—			(205,000		)
Principal tender on senior notes - HEP	—			—			—			—			(185,000		)	—			(185,000		)
Purchase of treasury stock	(209,600		)	—			—			(209,600		)	—			—			(209,600		)
Structured stock repurchase agreement	8,620			—			—			8,620			—			—			8,620
Contribution from joint venture partner	—			—			—			—			6,000			—			6,000
Contribution from general partner	—			(9,000		)	(1,286		)	(10,286		)	10,286			—			—
Distribution from HEP upon UNEV transfer	—			260,922			—			260,922			(260,922		)	—			—
Dividends	(658,085		)	—			—			(658,085		)	—			—			(658,085		)
Distributions to noncontrolling interest	—			—			—			—			(122,777		)	63,989			(58,788		)
Excess tax benefit from equity-based compensation	23,361			—			—			23,361			—			—			23,361
Purchase of units for incentive grants - HEP	—			—			—			—			(5,240		)	—			(5,240		)
Deferred financing costs	—			(67		)	—			(67		)	(3,238		)	—			(3,305		)
Other	—			(1,303		)	—			(1,303		)	(198		)	—			(1,501		)
	(1,040,704		)	323,452			(1,286		)	(718,538		)	(118,239		)	63,989			(772,788		)
Cash and cash equivalents
Increase (decrease) for the period	172,917			7,010			—			179,927			(1,132		)	—			178,795
Beginning of period	1,575,891			(3,358		)	2			1,572,535			6,369			—			1,578,904
End of period	$	1,748,808		$	3,652		$	2		$	1,752,462		$	5,237		$	—		$	1,757,699

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			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		$	(669,379	)	$	5,887		$	1,269,716		$	108,948		$	(40,273	)	$	1,338,391

Cash flows from investing activities:
Additions to properties, plants and equip	(7,585		)	(150,441		)	—			(158,026		)	—			—			(158,026		)
Additions to properties, plants and equip – HEP	—			—			—			—			(216,215		)	—			(216,215		)
Increase in cash due to merger with Frontier	182			872,557			—			872,739			—			—			872,739
Investment in Sabine Biofuels	(9,125		)	—			—			(9,125		)	—			—			(9,125		)
Purchases of marketable securities	(561,899		)	—			—			(561,899		)	—			—			(561,899		)
Sales and maturities of marketable securities	301,020			—			—			301,020			—			—			301,020
	(277,407		)	722,116			—			444,709			(216,215		)	—			228,494
Cash flows from financing activities:
Net borrowings under credit agreement – HEP	—			—			—			—			41,000			—			41,000
Repayments of promissory notes	—			77,100			—			77,100			(77,100		)	—			—
Proceeds from issuance of common units – HEP	—			—			—			—			75,815			—			75,815
Purchase of treasury stock	(42,795		)	—			—			(42,795		)	—			—			(42,795		)
Principal tender on senior notes – HFC	(8,203		)	—			—			(8,203		)	—			—			(8,203		)
Contribution to HEP	—			(123,000		)	(5,887		)	(128,887		)	128,887			—			—
Contribution from UNEV joint venture partner	—			—			—			—			33,500			—			33,500
Dividends	(252,133		)	—			—			(252,133		)	—			—			(252,133		)
Distributions to noncontrolling interest	—			—			—			—			(91,506		)	40,632			(50,874		)
Excess tax benefit from equity-based compensation	1,804			—			—			1,804			—			—			1,804
Purchase of units for restricted grants - HEP	—			—			—			—			(1,641		)	—			(1,641		)
Deferred financing costs	(8,665		)	—			—			(8,665		)	(3,150		)	—			(11,815		)
Other	—			(1,160		)	—			(1,160		)	(221		)	(359		)	(1,740		)
	(309,992		)	(47,060		)	(5,887		)	(362,939		)	105,584			40,273			(217,082		)
Cash and cash equivalents
Increase (decrease) for the period:	1,345,809			5,677			—			1,351,486			(1,683		)	—			1,349,803
Beginning of period	230,082			(9,035		)	2			221,049			8,052			—			229,101
End of period	$	1,575,891		$	(3,358	)	$	2		$	1,572,535		$	6,369		$	—		$	1,578,904

Table of Contents

HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued



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		$	70,949		$	—	$	211,883		$	107,721		$	(36,349	)	$	283,255

Cash flows from investing activities:
Additions to properties, plants and equip	(1,573		)	(102,149		)	—		(103,722		)	—			—			(103,722		)
Additions to properties, plants and equip – HEP	—			—			—		—			(109,510		)	—			(109,510		)
Proceeds from sale of assets	—			39,040			—		39,040			(39,040		)	—			—
	(1,573		)	(63,109		)	—		(64,682		)	(148,550		)	—			(213,232		)
Cash flows from financing activities:
Net repayments under credit agreement – HEP	—			—			—		—			(47,000		)	—			(47,000		)
Proceeds from issuance of senior notes – HEP	—			—			—		—			147,540			—			147,540
Purchase of treasury stock	(1,368		)	—			—		(1,368		)	—			—			(1,368		)
Contribution to HEP	—			(57,000		)	—		(57,000		)	57,000			—			—
Contribution from UNEV joint venture partner	—			—			—		—			23,500			—			23,500
Dividends	(31,868		)	—			—		(31,868		)	—			—			(31,868		)
Purchase price in excess of transferred basis in assets	—			54,046			—		54,046			(54,046		)	—			—
Distributions to noncontrolling interest	—			—			—		—			(84,426		)	35,933			(48,493		)
Excess tax benefit from equity-based compensation	(1,094		)	—			—		(1,094		)	—			—			(1,094		)
Purchase of units for restricted grants - HEP	—			—			—		—			(2,704		)	—			(2,704		)
Deferred financing costs	(2,627		)	—			—		(2,627		)	(494		)	—			(3,121		)
Other	118			(1,444		)	—		(1,326		)	—			416			(910		)
	(36,839		)	(4,398		)	—		(41,237		)	39,370			36,349			34,482
Cash and cash equivalents
Increase (decrease) for the period:	102,522			3,442			—		105,964			(1,459		)	—			104,505
Beginning of period	127,560			(12,477		)	2		115,085			9,511			—			124,596
End of period	$	230,082		$	(9,035	)	$	2	$	221,049		$	8,052		$	—		$	229,101

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HOLLYFRONTIER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Continued


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 $2,106.6 million (10%), $2,035.1 million (13%) and $1,616.0 million (19%) of our revenues for the years ended December 31, 2012, 2011 and 2010, respectively, and Shell Oil accounted for $2,323.6 million (12%) and $1,540.6 million (10%) for the years ended December 31, 2012 and 2011, respectively. Our export sales were to an affiliate of PEMEX and accounted for $429.4 million (2%), $370.0 million (2%) and $323.2 million (4%) of our revenues for the years ended December 31, 2012, 2011 and 2010, 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, 2012
Sales and other revenues	$	4,931,738	$	4,806,681	$	5,204,798	$	5,147,507	$	20,090,724
Operating costs and expenses	$	4,512,174	$	3,993,544	$	4,226,494	$	4,474,366	$	17,206,578
Income from operations	$	419,564	$	813,137	$	978,304	$	673,141	$	2,884,146
Income before income taxes	$	387,426	$	788,088	$	960,272	$	652,209	$	2,787,995
Net income attributable to HollyFrontier stockholders	$	241,696	$	493,499	$	600,373	$	391,604	$	1,727,172
Net income per share attributable to HollyFrontier stockholders - basic	$	1.16	$	2.40	$	2.95	$	1.92	$	8.41
Net income per share attributable to HollyFrontier stockholders - diluted	$	1.16	$	2.39	$	2.94	$	1.92	$	8.38
Dividends per common share	$	0.600	$	0.650	$	1.150	$	0.700	$	3.100
Average number of shares of common stock outstanding:
Basic	208,531		205,727		203,557		203,458		205,289
Diluted	209,138		206,481		204,434		204,453		206,184

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

100

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

We have had no change in, or disagreement with, our independent registered public accountants on matters involving accounting and financial disclosure.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Exchange Act as of the end of the period covered by this annual report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2012.

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 2012 that would need to be reported on Form 8-K that have not previously been reported.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.

Item 11. Executive Compensation

The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.

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

The information required by Items 404 and 407(a) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The information required by Item 9(e) of Schedule 14A in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) Documents filed as part of this report

(1) Index to Consolidated Financial Statements



	Page in Form 10-K

Report of Independent Registered Public Accounting Firm	57

Consolidated Balance Sheets at December 31, 2012 and 2011	58

Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010	59

Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	60

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	61

Consolidated Statements of Equity for the years ended December 31, 2012, 2011 and 2010	62

Notes to Consolidated Financial Statements	63

(2) Index to Consolidated Financial Statement Schedules

All schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

(3) Exhibits

The Exhibit Index on pages 105 to 113 of this Annual Report on Form 10-K lists the exhibits that are filed or furnished, as applicable, as part of this Annual Report on Form 10-K.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.




	HOLLYFRONTIER CORPORATION
	(Registrant)

Date: February 27, 2013		/s/ Michael C. Jennings
		Michael C. Jennings
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and as of the date indicated.



Signature	Capacity	Date

/s/ Michael C. Jennings	Chief Executive Officer and	February 27, 2013
Michael C. Jennings	President

/s/ Douglas S. Aron	Executive Vice President and	February 27, 2013
Douglas S. Aron	Chief Financial Officer
	(Principal Financial Officer)

/s/ J.W. Gann, Jr.	Vice President, Controller and	February 27, 2013
J.W. Gann, Jr.	Chief Accounting Officer
	(Principal Accounting Officer)

/s/ Denise C. McWatters	Senior Vice President, General	February 27, 2013
Denise C. McWatters	Counsel and Secretary

/s/ Douglas Y. Bech	Director	February 27, 2013
Douglas Y. Bech

/s/ Buford P. Berry	Director	February 27, 2013
Buford P. Berry

/s/ Leldon Echols	Director	February 27, 2013
Leldon Echols

/s/ R. Kevin Hardage	Director	February 27, 2013
R. Kevin Hardage

/s/ Robert J. Kostelnik	Director	February 27, 2013
Robert J. Kostelnik

/s/ James H. Lee	Director	February 27, 2013
James H. Lee

/s/ Robert G. McKenzie	Director	February 27, 2013
Robert G. McKenzie

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Signature	Capacity	Date

/s/ Franklin Myers	Director	February 27, 2013
Franklin Myers

/s/ Michael E. Rose	Director	February 27, 2013
Michael E. Rose

/s/ Tommy A. Valenta	Director	February 27, 2013
Tommy A. Valenta

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HOLLYFRONTIER CORPORATION

INDEX TO EXHIBITS

Exhibits are numbered to correspond to the exhibit table

in Item 601 of Regulation S-K



Exhibit Number		Description

2.1		Asset Sale and Purchase Agreement, dated October 19, 2009, between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed October 21, 2009, File No. 1-03876).

2.2		Amendment No. 1 to Asset Sale and Purchase Agreement, dated December 1, 2009, between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed December 7, 2009, File No. 1-03876).

2.3		Asset Sale and Purchase Agreement, dated April 15, 2009, between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed April 16, 2009, File No. 1-03876).

2.4		Agreement and Plan of Merger among Holly Corporation, North Acquisition, Inc. and Frontier Oil Corporation, dated February 21, 2011 (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed February 22, 2011, File No. 1-03876).

3.1		Amended and Restated Certificate of Incorporation of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).

3.2		Amended and Restated Bylaws of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K filed November 21, 2011, File No. 1-03876).

4.1		Indenture, dated February 28, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, providing for the issuance of 6.25% Senior Notes due 2015 (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 HEP Fin-Tex/Trust-River, L.P., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors 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 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 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 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).

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

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Exhibit Number		Description

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

4.10		Ninth 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).

4.11		Tenth Supplemental Indenture, dated March 12, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 12, 2012, File No. 1-32225).

4.12		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).

4.13		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).

4.14		Indenture, dated September 17, 2008, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K filed September 17, 2008, File No. 1-07627).

4.15		First Supplemental Indenture, dated September 17, 2008, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed September 17, 2008, File No. 1-07627).

4.16		Second Supplemental Indenture, dated May 26, 2011, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K filed May 27, 2011, File Number 1-07627).

4.17		Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).

4.18		Form of 8.5% Senior Note Due 2016 (incorporated by reference to Exhibit 4.3 of Frontier Oil Corporation's Current Report on Form 8-K filed September 17, 2008, File Number 1-07627).

4.19		Indenture, dated June 10, 2009, among Holly Corporation, the Guarantors and U.S. Bank Trust National Association, providing for the issuance of 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued thereunder) (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed June 11, 2009, File No. 1-03876).

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

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

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

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Exhibit Number		Description

4.23		First Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, File No. 1-32225).

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

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

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

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

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

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

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

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

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

4.33		First Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, File No. 1-03876).

10.1		Option Agreement, dated January 31, 2008, 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, 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		Termination of Option Agreement, dated July 12, 2012, among HollyFrontier Corporation, HEP UNEV Pipeline LLC (f/k/a 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 10.6 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).

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Exhibit Number		Description

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

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

10.6		Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.7		Tulsa Equipment and Throughput Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Holly Energy Partners L.P.'s Current Report on Form 8-K filed August 6, 2009, File No. 1-32225).

10.8		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).

10.9		Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing - Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.8 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.10		Tulsa Purchase Option Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Holly Energy Partners L.P.'s Current Report on Form 8-K filed August 6, 2009, File No. 1-32225).

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

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

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

10.14		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).

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

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

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Exhibit Number		Description

10.17		First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated March 31, 2010, 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).

10.18		Amendment to First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated June 11, 2010, 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 the quarterly period ended June 30, 2010, File No. 1-32225).

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

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

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

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

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

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

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

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

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

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

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

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Exhibit Number		Description

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

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

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

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

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

10.35		Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (“the Agreement”) and First Amendment to the Agreement dated September 18, 2000, Second Amendment to the Agreement dated September 21, 2000, Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment to the Agreement dated February 22, 2001, Fifth Amendment to the Agreement dated August 14, 2001, Sixth Amendment to the Agreement dated November 5, 2001, Seventh Amendment to the Agreement dated April 22, 2002, Eighth Amendment to the Agreement date d May 30, 2003, Ninth Amendment to the Agreement dated May 25, 2004, Tenth Amendment to the Agreement dated May 3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006, Twelfth Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the Agreement dated September 30, 2007, Fourteenth Amendment to the Agreement dated May 1, 2008 and Fifteenth Amendment to the Agreement dated May 28, 2008 (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2008, File No. 1-07627).

10.36		Sixteenth Amendment dated November 1, 2009, to the Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.14 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-07627).

10.37		Master Crude Oil Purchase and Sale Contract, dated November 1, 2010, among BNP Paribas Energy Trading GP, BNP Paribas Energy Trading Canada Corp., Frontier Oil and Refining Company and Frontier Oil Corporation (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627).

10.38		Guaranty, dated November 1, 2010, by Frontier Oil Corporation in favor of BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp. (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627).

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

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

10.41		Amended and Restated Limited Liability Company Agreement of HEP UNEV Holdings LLC, dated July 12, 2012, among HEP UNEV Holdings LLC, HollyFrontier Holdings LLC and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.5 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).

10.42+		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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Exhibit Number		Description

10.43+		HollyFrontier Corporation Long-Term Incentive Compensation Plan (formerly the Holly Corporation Long-Term Incentive Compensation Plan), as amended and restated on May 24, 2007 as approved at the Annual Meeting of Stockholders of Holly Corporation on May 24, 2007 (incorporated by reference to Exhibit 10.4 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).

10.44+		First Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).

10.45+		Second Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed May 18, 2011, File No. 1-03876).

10.46+		Third Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.6 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).

10.47+		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).

10.48+		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).

10.49+		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).

10.50+		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).

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

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

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

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

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

10.56+		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).

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

10.58+		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).

10.59+		Form of Performance Share Unit Agreement (for 162(m) covered employees) (incorporated by reference to Exhibit 4.11 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).

10.60+		Form of Performance Share Unit Agreement (for non-162(m) covered employees) (incorporated by reference to Exhibit 4.12 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).

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Exhibit Number		Description

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

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

10.63+*		Form of Restricted Stock Unit Agreement (for non-employee directors).

10.64+*		Form of Notice of Grant of Restricted Stock Units (for non-employee directors).

10.65+		Waiver Agreement, dated February 21, 2011, 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 quarterly period ended March 31, 2011, File No. 1-03876).

10.66+		Waiver Agreement, dated February 21, 2011, 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 quarterly period ended March 31, 2011, File No. 1-03876).

10.67+		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).

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

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

10.70+		HollyFrontier Corporation Omnibus Incentive Compensation Plan (formerly the Frontier Oil Corporation Omnibus Incentive Compensation Plan) (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).

10.71+		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).

10.72+		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).

10.73+*		HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan (formerly the Frontier Deferred Compensation Plan).

10.74+		Form of Indemnification Agreement between Frontier and each of its officers and directors (incorporated by reference to Exhibit 10.41 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31, 2006, File No. 1-07627).

10.75+		Form of Indemnification Agreement between HollyFrontier Corporation and each of its officers and directors (incorporated by reference to Exhibit 10.79 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876).

21.1*		Subsidiaries of Registrant.

23.1*		Consent of Independent Registered Public Accounting Firm.

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

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

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Exhibit Number		Description

32.1**		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

101++		The following financial information from Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Equity, and (vi) Notes to the Consolidated Financial Statements.

* Filed herewith.

** Furnished herewith.

+ Constitutes management contracts or compensatory plans or arrangements.

++ Filed electronically herewith.

113