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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2010


o		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

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)


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

100 Crescent Court, Suite 1600, Dallas, Texas		75201-6915
(Address of principle executive offices)		(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.01 par value registered on the New York Stock Exchange.

Securities registered pursuant to 12(g) of the Act:
None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

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 o No þ

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 þ No o

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

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. þ

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
	(Do not check if a 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 o No þ

On June 30, 2010 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $1,183 million. (This is not to be deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.)

53,303,425 shares of Common Stock, par value $.01 per share, were outstanding on February 8, 2011.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 12, 2011, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2010, are incorporated by reference in Part III.

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;

	•		risks and uncertainties with respect to our proposed “merger of equals” with Frontier Oil Corporation, including our ability to complete the merger in the anticipated timeframe or at all, the diversion of management in connection with the merger and our ability to realize fully or at all the anticipated benefits of the merger; 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.

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

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

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

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

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

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

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

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

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

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

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

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

“LPG” means liquid petroleum gases.

“LSG,” or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.

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“Lube extraction unit” is a unit used in the lube process that separates aromatic oils from paraffinic oils using furfural as a solvent.

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

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

“MMBTU” means one million British thermal units.

“MMSCFD” means one million standard cubic feet per day.

“MTBE” means methyl tertiary butyl ether, a high octane gasoline blend stock that is used to make various grades of gasoline.

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

“PPM” means parts-per-million.

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

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

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

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

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

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

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

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

“ULSD,” or ultra low sulfur diesel, means diesel fuel that contains less than 15 PPM of total sulfur.

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

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INDEX TO DEFINED TERMS AND NAMES

The following other terms and names that appear in this form 10-K are defined on the following pages:


	Page
	Reference
Agreement		43
Alon		13
Alon PTA		24
Beeson Pipeline		23
CAA		26
CERCLA		26
CWA		26
Court of Appeals		41
EBITDA		48
EPA		15
Exchange Act		110
FERC		23
Frontier		9
GAAP		8
GHG		31
Guarantor Restricted Subsidiaries		104
HEP		8
HEP ATA		23
HEP CPTA		23
HEP ETA		23
HEP IPA		23
HEP NPA		23
HEP PTA		23
HEP PTTA		23
HEP RPA		23
HEP Amended Credit Agreement		54
HEP Credit Agreement		54
HEP6.25% Senior Notes		54
HEP8.25% Senior Notes		54
HEP Senior Notes		54
Holly 9.875% Senior Notes		54
Holly Asphalt		9
Holly Credit Agreement		53
HPI		53
HRM-Tulsa		43
LIBOR		62
LIFO		38
MDEQ		42
MRC		42
MSAT2		15
Magellan		13
Merger		9
NEP		42
NPDES		26
Navajo Refinery		9
Non-Guarantor Non-Restricted Subsidiaries		104
Non-Guarantor Restricted Subsidiaries		104
ODEQ		43
OHSB		42
OSHA		42
OSHRC		42
Plains		8
Plan		101
PPI		23
PSM		43
Parent		104
RCRA		26
RINs		33
Restricted Subsidiaries		104
Rio Grande		23
Roadrunner Pipeline		23
SEC		8

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Items 1 and 2. Business and Properties

COMPANY OVERVIEW

References herein to Holly Corporation include Holly Corporation 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 Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions or obligations between HEP and Holly Corporation 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 Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

We are principally an independent petroleum refiner that produces high value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We were incorporated in Delaware in 1947 and maintain our principal corporate offices at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915. Our telephone number is 214-871-3555 and our internet website address is www.hollycorp.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 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 “HOC.”

On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate of Sunoco, Inc. (“Sunoco”) for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage tanks and certain refining-related crude oil receiving pipeline facilities, that were acquired as part of the refinery assets for $40 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 Refinery east facility”) for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we reimbursed Sinclair $8.4 million upon their completion of certain environmental projects at the refinery in July 2010. The refinery also produces gasoline, diesel fuel and jet fuel products and serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities (collectively, the “Tulsa Refinery”). This will result in the Tulsa Refinery having an integrated crude processing rate of 125,000 BPSD.

On February 29, 2008, we sold certain crude pipelines and tankage assets to HEP for $180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Woods Cross and Navajo Refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico and crude oil and product pipelines that support our refinery in Woods Cross, Utah. 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,

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we reconsolidated HEP effective March 1, 2008. Intercompany transactions with HEP are eliminated in our consolidated financial statements.

HEP made a number of acquisitions in 2010 and 2009. Information on these acquisitions can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”

As of December 31, 2010, we:

	•		owned and operated three refineries consisting of a petroleum 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 in Woods Cross, Utah (the “Woods Cross Refinery”) and the Tulsa Refinery;

	•		owned and operated Holly Asphalt Company (“Holly Asphalt”) which manufactures and markets asphalt products from various terminals in Arizona, New Mexico and Texas;

	•		owned a 75% interest in a 12-inch refined products pipeline project 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

	•		owned a 34% interest in HEP (which includes our 2% general partnership interest), which owns and operates logistics assets including approximately 2,500 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; eight refinery loading rack facilities; a refined products tank farm facility; on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries, on-site refined product tankage at our Tulsa Refinery and a 25% interest in a 95-mile, crude oil pipeline joint venture (the “SLC Pipeline”).

Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns the Navajo Refinery. The Navajo Refinery has a crude capacity of 100,000 BPSD, can process up to 100% sour crude oil and serves markets in the southwestern United States and northern Mexico. Our Woods Cross Refinery, located just north of Salt Lake City, Utah has a crude capacity of 31,000 BPSD and is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly-owned subsidiaries. The Woods Cross Refinery processes regional sweet and Canadian sour crude oils and serves markets in Utah, Idaho, Nevada, Wyoming and eastern Washington. Our Tulsa Refinery located in Tulsa, Oklahoma has a crude capacity of 125,000 BPSD and is owned and operated by Holly Refining & Marketing Company — Tulsa LLC, one of our wholly-owned subsidiaries. The Tulsa Refinery primarily processes sweet crude oils, however, has the capability to process sour crude oils when economics dictate, and serves the Mid-Continent region of the United States.

Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our Navajo, Woods Cross and Tulsa Refineries and Holly Asphalt. Information regarding Holly Asphalt can be found under the “Refinery Operations” section provided below. The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation).

Recent Developments

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination of us and Frontier Oil Corporation (the “Merger”). Frontier Oil Corporation (“Frontier”) operates a 135,000 bpd refinery located in El Dorado, Kansas, and a 52,000 bpd refinery located in Cheyenne, Wyoming, and markets its refined products principally along the eastern slope of the Rocky Mountains and in other neighboring plains states.

Subject to the terms and conditions of the merger agreement which has been approved unanimously by both our and Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of Holly common stock for each share of Frontier common stock if the Merger is completed.

Completion of the Merger is subject to certain conditions, including, among others, (i) approval by our stockholders of the issuance of our common stock to Frontier’s stockholders in connection with the Merger, (ii) adoption of the merger agreement by Frontier’s stockholders, (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the registration statement on Form S-4 used to register the common stock to be issued as consideration for the Merger having been declared effective by the SEC and (v) the entry into a new credit facility for the combined company.

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The foregoing description of the merger agreement is not a complete description of all the parties’ rights and obligations under the merger agreement and is qualified in its entirety by reference to the merger agreement, which is filed as Exhibit 2.1 to our Current Report on Form 8-K as filed with the SEC on February 22, 2011.

REFINERY OPERATIONS

Our refinery operations include the operations of our three refineries. The following table sets forth information, including performance measures about our refinery operations that are not calculations based upon GAAP. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


	Years Ended December 31,
	2010			2009			2008
*Consolidated*
Crude charge (BPD) ⁽¹⁾		221,440			142,430			100,680
Refinery throughput (BPD) ⁽²⁾		234,910			154,940			114,130
Refinery production (BPD) ⁽³⁾		225,980			151,420			110,850
Sales of produced refined products (BPD)		228,140			151,580			111,950
Sales of refined products (BPD) ⁽⁴⁾		232,100			155,820			120,750

Refinery utilization ⁽⁵⁾		86.5	%		78.9	%		89.7	%

Average per produced barrel ⁽⁶⁾
Net sales	$	91.06		$	74.06		$	108.83
Cost of products ⁽⁷⁾		82.27			66.85			97.87

Refinery gross margin		8.79			7.21			10.96
Refinery operating expenses ⁽⁸⁾		5.08			5.24			5.14

Net operating margin	$	3.71		$	1.97		$	5.82


Refinery operating expenses per throughput barrel	$	4.94		$	5.12		$	5.05

Feedstocks:
Sour crude oil		35	%		49	%		63	%
Sweet crude oil		53	%		40	%		23	%
Black wax crude oil		3	%		5	%		4	%
Heavy sour crude oil		4	%		—	%		—	%
Other feedstocks and blends		5	%		6	%		10	%

Total		100	%		100	%		100	%


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

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

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

(4)		Includes refined products purchased for resale.

(5)		Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased by 15,000 BPSD effective April 1, 2009 (our Navajo Refinery expansion), 85,000 BPSD effective June 1, 2009 (our Tulsa Refinery west facility acquisition) and 40,000 BPSD effective December 1, 2009 (our Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD.

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

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

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

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Set forth below is information regarding our principal products.


	Years Ended December 31,
	2010			2009			2008
*Consolidated*
Sales of produced refined products:
Gasolines		49	%		51	%		58	%
Diesel fuels		31	%		31	%		32	%
Jet fuels		5	%		4	%		1	%
Fuel oil		2	%		2	%		3	%
Asphalt		3	%		2	%		3	%
Lubricants		5	%		4	%		—	%
Gas oil / intermediates		2	%		4	%		—	%
LPG and other		3	%		2	%		3	%

Total		100	%		100	%		100	%

We have several significant customers, one of which accounted for more than 10% of our business in 2010. For the year ended December 31, 2010, Sinclair accounted for $1,616 million or 19% of our revenues. In connection with our refinery acquisition from Sinclair in 2009, we entered into a refined products purchase agreement, or offtake agreement, with an affiliate of Sinclair. Information on this offtake agreement can be found under our discussion of the Tulsa Refinery provided later in this section of “Refinery Operations.” 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. Asphalt is sold to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing or blended into fuel oil.

Navajo Refinery

Facilities

The Navajo Refinery has a crude oil capacity of 100,000 BPSD and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. The Navajo Refinery converts approximately 92% of its raw materials throughput into high value light products. For 2010, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 57%, 32% and 3%, respectively, of the Navajo Refinery’s sales volumes.

The following table sets forth information about the Navajo Refinery operations, including non-GAAP performance measures. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


	Years Ended December 31,
	2010			2009			2008
*Navajo Refinery*
Crude charge (BPD) ⁽¹⁾		83,900			78,160			79,020
Refinery throughput (BPD) ⁽²⁾		94,270			88,900			90,790
Refinery production (BPD) ⁽³⁾		92,050			86,760			88,680
Sales of produced refined products (BPD)		92,550			87,140			89,580
Sales of refined products (BPD) ⁽⁴⁾		95,790			90,870			97,320

Refinery utilization ⁽⁵⁾		83.9	%		81.2	%		93.0	%

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	Years Ended December 31,
	2010			2009			2008
Average per produced barrel ⁽⁶⁾
Net sales	$	90.37		$	73.15		$	108.52
Cost of products ⁽⁷⁾		83.12			65.95			98.97

Refinery gross margin		7.25			7.20			9.55
Refinery operating expenses ⁽⁸⁾		4.95			4.81			4.58

Net operating margin	$	2.30		$	2.39		$	4.97


Refinery operating expenses per throughput barrel	$	4.86		$	4.71		$	4.52

Feedstocks:
Sour crude oil		81	%		85	%		79	%
Sweet crude oil		5	%		6	%		10	%
Heavy sour crude oil		4	%		—	%		—	%
Other feedstocks and blends		10	%		9	%		11	%

Total		100	%		100	%		100	%


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

(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 refinery.

(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 refinery.

(4)		Includes refined products purchased for resale.

(5)		Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased from 85,000 BPSD by 15,000 BPSD in the first quarter of 2009 (our 2009 Navajo Refinery expansion), increasing crude capacity to 100,000 BPSD.

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

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

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

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. Other supporting infrastructure includes approximately 2 million barrels of feedstock and product tankage at the site of which 0.2 million barrels of tankage are owned by HEP, maintenance shops, warehouses and office buildings. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. The Artesia facility is operated in conjunction with a refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970. The facility also has an additional 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. The Navajo Refinery completed a major maintenance turnaround in February 2010.

We distribute refined products from the Navajo Refinery to markets in Arizona, New Mexico, west Texas and northern Mexico primarily through two of HEP’s pipelines that extend 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, we use pipelines owned and leased by HEP to transport petroleum products to markets in central and northwest 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.

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Markets and Competition

The Navajo Refinery primarily serves the southwestern United States market, which has historically experienced a high growth rate, including El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and the northern Mexico market. 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 SFPP. In addition, the Navajo Refinery transports petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via HEP’s pipelines running from Artesia to San Juan County, New Mexico.

El Paso Market

The El Paso market for refined products is currently supplied by a number of area and gulf coast refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between ConocoPhillips and EnCana Corp.), Valero, Alon USA, Inc. (“Alon”), and Western Refining. Pipelines serving this market are owned by Magellan Midstream Partners, L.P. (“Magellan”), NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines, including Magellan’s Longhorn Pipeline acquired in 2009. We supply approximately 17% — 20% of the refined products consumed in the El Paso market.

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. We supply approximately 17% — 20% of the refined products consumed in the Arizona market, comprised primarily of Phoenix and Tucson, via the SFPP Pipeline.

New Mexico Markets

The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western Refining, Alon and WRB. We supply approximately 18% — 20% of the refined products consumed in the New Mexico market.

We use a common carrier pipeline out of El Paso to serve the Albuquerque market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in Bloomfield, New Mexico, which is located in the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of Albuquerque. These facilities permit us to ship light products to the Albuquerque and Santa Fe, New Mexico areas, which have historically experienced high growth rates. If needed, additional pump stations could further increase the pipeline’s capabilities.

Magellan’s Longhorn Pipeline is a 72,000 BPD common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market.

An additional factor that could affect some of our markets is the presence of pipeline capacity from El Paso and the West Coast into our Arizona markets. Additional increases in shipments of refined products from El Paso and the West Coast into our Arizona markets could result in additional downward pressure on refined product prices in these markets.

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Principal Products and Customers

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


	Years Ended December 31,
	2010			2009			2008
*Navajo Refinery*
Sales of produced refined products:
Gasolines		57	%		58	%		57	%
Diesel fuels		32	%		32	%		33	%
Jet fuels		3	%		2	%		1	%
Fuel oil		4	%		3	%		3	%
Asphalt		2	%		3	%		3	%
LPG and other		2	%		2	%		3	%

Total		100	%		100	%		100	%

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

Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, and retailers. Our gasoline produced at the Navajo Refinery is marketed in the southwestern United States, including the metropolitan areas of El Paso, Phoenix, Albuquerque, Bloomfield, and Tucson, and in portions of northern Mexico. The composition of gasoline differs, because of local regulatory requirements, depending on the area in which gasoline is to be sold. Diesel fuel is sold to other refiners, truck stop chains, wholesalers, and railroads. Jet fuel is sold for military and commercial airline use. All asphalt produced and purchased from third-parties is blended to fuel oil and is either sold locally, or is shipped by rail to the Gulf Coast, shipped by rail directly to our customers or marketed through Holly Asphalt to governmental entities, contractors or manufacturers. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing.

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.’s pipeline running from west Texas to Cushing Oklahoma. In 2010, the Navajo Refinery began processing heavy sour crude oil transported from Cushing through these pipelines. Cushing Oklahoma is a significant crude oil pipeline trading and storage hub that has access to regional crude production as well as United States onshore, Gulf of Mexico, Canadian and other foreign crudes.

We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in southeastern New Mexico 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.

Capital Improvement Projects

Our total capital budget for the Navajo Refinery for 2011 is $23.9 million. Additionally, capital costs of $2 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $24 million in capital costs in 2011, including capital projects approved in prior years. The following summarizes our key capital projects.

We completed Phase II of our major capital projects initiative at the Navajo Refinery in the second quarter of 2010, providing the refinery with the capability to process up to 40,000 BPSD of heavy type crudes. Phase II involved the installation of a new solvent deasphalter and the revamp of our Artesia crude and vacuum units. We completed Phase I of this initiative in the first quarter of 2009, which increased refining capacity to 100,000 BPSD. Phase I

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included the installation of a new mild hydrocracker, hydrogen plant and the expansion of our Lovington crude and vacuum units.

The Navajo Refinery currently plans to comply with new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations issued by the Environmental Protection Agency (“EPA”) by the fractionation of naphtha with existing equipment to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will purchase or use credits generated at the Tulsa Refinery to reduce benzene content to the required 0.62%. Due to our acquisition of the Tulsa Refinery facilities from Sunoco and Sinclair, our Navajo Refinery has until the end of 2011 to comply with the MSAT2 regulations because we no longer qualify for the small refiner’s exemption. Also, we will be installing a new storm water surge tank and upgrade several other processes at the refinery’s Artesia waste water treatment plant. These projects are expected to cost approximately $17 million.

Woods Cross Refinery

Facilities

The Woods Cross Refinery has a crude oil capacity of 31,000 BPSD and is located in Woods Cross, Utah. The Woods Cross Refinery processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2010, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 63%, 30% and 1%, respectively, of the Woods Cross Refinery’s sales volumes.

The following table sets forth information about the Woods Cross Refinery operations, including non-GAAP performance measures about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


	Years Ended December 31,
	2010			2009			2008
*Woods Cross Refinery*
Crude charge (BPD)⁽¹⁾		25,870			24,900			21,660
Refinery throughput (BPD) ⁽²⁾		27,540			26,520			23,340
Refinery production (BPD) ⁽³⁾		27,020			25,750			22,170
Sales of produced refined products (BPD)		27,810			26,870			22,370
Sales of refined products (BPD) ⁽⁴⁾		27,980			27,250			23,430

Refinery utilization ⁽⁵⁾		83.5	%		80.3	%		79.5	%

Average per produced barrel ⁽⁶⁾
Net sales	$	94.26		$	70.25		$	110.07
Cost of products ⁽⁷⁾		75.54			58.98			93.47

Refinery gross margin		18.72			11.27			16.60
Refinery operating expenses ⁽⁸⁾		6.09			6.60			7.42

Net operating margin	$	12.63		$	4.67		$	9.18


Refinery operating expenses per throughput barrel	$	6.15		$	6.69		$	7.11

Feedstocks:
Heavy sour crude oil		6	%		5	%		1	%
Sweet crude oil		59	%		62	%		72	%
Black wax crude oil		30	%		28	%		21	%
Other feedstocks and blends		5	%		5	%		6	%

Total		100	%		100	%		100	%


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

(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 refinery.

(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 refinery.

(4)		Includes refined products purchased for resale.

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(5)		Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased by 5,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion), increasing crude capacity to 31,000 BPSD.

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

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

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

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. Other 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, maintenance shops, warehouses and office buildings. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since before 1950. The crude oil capacity of the Woods Cross Refinery is 31,000 BPSD and the facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil. The Woods Cross Refinery completed a major maintenance turnaround in September 2008.

We own and operate 4 miles of hydrogen pipeline that allows us to connect 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.

Markets and Competition

The Woods Cross Refinery is one of five refineries located in Utah. We estimate that the four refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately 150,000 BPD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and ConocoPhillips. The Woods Cross Refinery’s primary markets include Utah, Idaho, Nevada, Wyoming and eastern Washington. 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.

Utah Market

The Utah market for refined products is currently supplied primarily by a number of local refiners and the Pioneer Pipeline. Local area refiners include Woods Cross, Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and ConocoPhillips. We supply approximately 15% — 20% of the refined products consumed in the Utah market, to branded and unbranded customers.

Idaho, Wyoming, Eastern Washington and Nevada Markets

We supply approximately 2% of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery ships refined products over Chevron’s common carrier pipeline system to numerous terminals, including HEP’s terminals at Boise and Burley, Idaho and Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Northwest Terminalling Pipeline Company. We sell to branded and unbranded customers in these markets. We also truck refined products to Las Vegas, Nevada.

The Idaho market for refined products is primarily supplied via Chevron’s common carrier pipeline system from refiners located in the Salt Lake City area and products supplied from the Pioneer Pipeline system. Refiners that could potentially supply the Chevron and Pioneer Pipeline systems include Woods Cross, Chevron, Tesoro, Big West, Silver Eagle, Sinclair, ConocoPhillips and ExxonMobil.

We market refined products in the Wyoming market on a limited basis. Refiners that supply Wyoming include Sinclair, ConocoPhillips, ExxonMobil and Frontier.

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The eastern Washington market is supplied by two common carrier pipelines, Chevron and Yellowstone. Product is also shipped into the area via rail from various points in the United States and Canada. Refined products shipped on Chevron’s pipeline system are supplied by refiners and other pipelines located in the Salt Lake City area and from refiners located in the Pacific Northwest. Pacific Northwest refiners include BP, Tesoro, Shell, ConocoPhillips and US Oil. Products supplied from the sources located in the Pacific Northwest area are generally shipped over the Columbia River via barge at Pasco, Washington.

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 and Customers

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


	Years Ended December 31,
	2010			2009			2008
*Woods Cross Refinery*
Sales of produced refined products:
Gasolines		63	%		64	%		63	%
Diesel fuels		30	%		28	%		29	%
Jet fuels		1	%		1	%		—	%
Fuel oil		1	%		3	%		5	%
Asphalt		3	%		2	%		1	%
LPG and other		2	%		2	%		2	%

Total		100	%		100	%		100	%

Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, due to local regulatory requirements, depending on the area in which gasoline is to be sold. Diesel fuel is sold to other refiners, truck stop chains and wholesalers. Limited quantities of jet fuel are sold for commercial airline use. Asphalt produced is either blended to fuel oil or is sold locally, or shipped by rail to the Gulf Coast, shipped by rail directly to our customers or marketed through Holly Asphalt to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers.

Crude Oil and Feedstock Supplies

The Woods Cross Refinery currently obtains its supply of crude oil from suppliers in Canada, Wyoming, Utah and Colorado as delivered via common carrier pipelines that originate in Canada, Wyoming and Colorado. In 2009, we also began receiving crude oil via the SLC Pipeline, a joint venture common carrier pipeline in which HEP owns a 25% interest. Supplies of black wax crude oil are shipped via truck.

Capital Improvement Projects

Our total capital budget for the Woods Cross Refinery for 2011 is $7.7 million. Additionally, capital costs of $0.4 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $13 million in capital costs in 2011, including capital projects approved in prior years. The following summarizes our key capital projects.

Our Woods Cross Refinery is required to install a wet gas scrubber on its FCC unit by the end of 2012. We estimate the total cost to be $12 million. The MSAT2 solution for the refinery involves revamping its naphtha fractionation unit and installing a benzene saturation unit at an estimated cost of $10 million. These projects will reduce benzene levels in gasoline below the 1.3% annual average level. The Woods Cross Refinery will purchase credits to meet the 0.62% benzene requirement. Like our Navajo Refinery, our Woods Cross Refinery has until the end of 2011 to comply with the MSAT2 regulations.

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Tulsa Refinery

Facilities

On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery in Tulsa, Oklahoma from Sunoco. On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BSPD refinery that is also located in Tulsa, Oklahoma from Sinclair. We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.

The Tulsa Refinery primarily processes sweet crude oils into high value light products such as gasoline, diesel fuel, jet fuel and specialty lubricants, however, has the capability to process sour crude oils when economics dictate. For 2010, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 38%, 31%, 8% and 11%, respectively, of the Tulsa Refinery’s sales volumes.

The following table sets forth information about the Tulsa Refinery operations, including non-GAAP performance measures about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.


	Years Ended December 31,
	2010			2009⁽⁹⁾
*Tulsa Refinery*
Crude charge (BPD)⁽¹⁾		111,670			39,370
Refinery throughput (BPD) ⁽²⁾		113,100			39,520
Refinery production (BPD) ⁽³⁾		106,910			38,910
Sales of produced refined products (BPD)		107,780			37,570
Sales of refined products (BPD) ⁽⁴⁾		108,330			37,700

Refinery utilization ⁽⁵⁾		89.3	%		74.0	%

Average per produced barrel ⁽⁶⁾
Net sales	$	90.84		$	78.89
Cost of products ⁽⁷⁾		83.29			74.56

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

Net operating margin	$	2.61		$	(0.92	)


Refinery operating expenses per throughput barrel	$	4.71		$	4.99

Feedstocks:
Sour crude oil		5	%		—	%
Sweet crude oil		92	%		100	%
Heavy sour crude oil		3	%		—	%

Total		100	%		100	%


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

(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 refinery.

(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 refinery.

(4)		Includes refined products purchased for resale.

(5)		Represents crude charge divided by total crude capacity (BPSD). The crude capacity of 85,000 BPSD (our June 2009 Tulsa Refinery west facility acquisition) was increased by 40,000 BPSD in the fourth quarter of 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing crude capacity to 125,000 BPSD.

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

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

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

(9)		The amounts reported for the Tulsa Refinery for the year ended December 31, 2009 include crude oil processed and products yielded from the refinery for the period from June 1, 2009 through December 31, 2009 only, and averaged over the 365 days for the year ended. Operating data for the period from June 1, 2009 (date of Tulsa Refinery west facility acquisition) through December 31, 2009 and for the period from December 1, 2009 (date of Tulsa Refinery east facility acquisition) through December 31, 2009 is as follows:


	Period From		Period From
	June 1, 2009		December 1, 2009
	Through		Through
	December 31, 2009		December 31, 2009
*Tulsa Refinery*
Crude charge (BPD)		67,160		93,810
Refinery production (BPD)		66,360		99,810
Sales of produced refined products (BPD)		64,080		96,170
Sales of refined products (BPD)		64,300		96,170

The Tulsa Refinery west facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa Refinery west facility consist of crude distillation (with light ends recovery), naphtha hydrodesulfurization, catalytic reforming, propane de-asphalting, lubes extraction, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. The refinery’s supporting infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains, and an additional 1.2 million barrels of tank capacity that are currently out of service and could be made available for future use.

The Tulsa Refinery 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 Refinery east facility consist of crude distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. Additions and improvements to the facility since late 2004 include a scanfining unit to meet 2006 gasoline sulfur content requirements, a new naphtha hydro desulphurizer unit in 2005, a new sulfur plant, modifications to the distillate hydro desulphurizer unit, a new tail gas unit installed on the new sulfur plant and the conversion of the reformer from a 17,000 BPD semi-regenerative reformer to a 22,000 BPD continuous catalyst regeneration reformer (thereby increasing its capacity, octane capability and yield of gasoline). The refinery’s supporting infrastructure includes approximately 3.75 million barrels of tankage capacity on the refinery’s premises, of which approximately 3.4 million barrels of tankage is owned by HEP. We recently completed a turnaround of both Tulsa Refinery west and east facilities in January 2011.

We are integrating the Tulsa Refinery west and east facilities that will result in a single, highly complex refinery having an integrated crude processing rate of approximately 125,000 BPSD, primarily by sending intermediate streams from one facility to the other for further processing. Pursuant to this plan, high sulfur diesel and various gas oil streams will be sent from the Tulsa Refinery west facility to be processed in the diesel hydrotreater and FCC units, respectively, at the Tulsa Refinery east facility. Various heavy oil streams are sent from the Tulsa Refinery east facility to be processed in our coker unit at our Tulsa Refinery west facility. The majority of the naphtha from the west facility is processed at the east facility and is delivered along with gas oils via the existing interconnect line. Hydrogen and fuel gas will be shared between the two refinery facilities upon completion of additional interconnect pipelines.

The Tulsa Refinery produces fuel products including gasoline, diesel fuel, jet fuel, #1 fuel oil, asphalt, heavy fuels and LPGs and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America.

Markets and Competition

The Tulsa Refinery primarily serves the Mid-Continent region of the United States. Distillates and gasolines are primarily delivered from the Tulsa Refinery to market via two pipelines owned and operated by Magellan. These pipelines connect the refinery to distribution channels throughout Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, the Tulsa Refinery has a proprietary diesel transfer line to the

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local Burlington Northern Santa Fe Railroad depot, and HEP’s on-site truck and rail racks facilitate access to local refined product markets.

In conjunction with our acquisition of the Tulsa Refinery east facility, we entered a five-year offtake agreement with an affiliate of Sinclair whereby Sinclair has 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. The offtake agreement can be renewed by Sinclair for an additional five-year term.

Our Tulsa Refinery also produces specialty lubricant products including agricultural oils, base oils, process oils and waxes that are sold throughout the United States and to customers with operations in Central America and South America. Our refinery’s production represents 6% of paraffinic oil capacity and 12% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.

The refinery’s asphalt and roofing flux products are sold via truck or railcar directly from the refinery or to customers throughout the Mid-Continent region.

Principal Products and Customers

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


	Years Ended December 31,
	2010			2009
*Tulsa Refinery*
Sales of produced refined products:
Gasolines		38	%		26	%
Diesel fuels		31	%		29	%
Jet fuels		8	%		10	%
Lubricants		11	%		16	%
Gas oil / intermediates		4	%		17	%
Asphalt		5	%		—	%
LPG and other		3	%		2	%

Total		100	%		100	%

Light products are shipped by product pipelines and are also made available to customers through truck and rail loading facilities. The Tulsa Refinery’s principal customers for conventional gasoline include Sinclair, other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, because of regulatory requirements, depending on the area in which gasoline is to be sold. Sinclair and railroads are the primary diesel customers. Jet fuel is sold primarily for commercial use. LPGs are sold to LPG wholesalers and retailers.

The specialty lubricant products produced at the Tulsa Refinery are high value products that provide significantly higher margin contribution to the refinery. Specialty lubricant products are sold in both commercial and specialty markets. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural oils, primarily formulated as supplemental carriers for herbicides, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive and candle-making markets.

Asphalt and roofing flux are sold primarily to paving contractors and manufacturers of roofing products.

Crude Oil and Feedstock Supplies

The Tulsa Refinery is 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 refinery to this pipeline and storage hub provides the refinery with the flexibility to optimize its crude slate with a wide variety of crude oil supply options.

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The refinery also purchases other feedstocks on an opportunistic basis. From time to time, the refinery purchases naphtha, gasoline components, transmix, light cycle oil, lube blend stocks or residuals from other refineries. These feedstocks are delivered by truck, rail car or pipeline, depending on product and logistical requirements.

Capital Improvement Projects

Our total capital budget for the Tulsa Refinery for 2011 is $100 million. Additionally, capital costs of $9.4 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $70 million in capital costs in 2011, including capital projects approved in prior years. The following summarizes our key capital projects.

We are proceeding with the integration project of our Tulsa Refinery west and east facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD. The integration project involves the installation of interconnect pipelines that will permit us to transfer various intermediate streams between the two facilities. Currently, we are using an existing third-party line for the transfer of intermediates from the west facility to the east facility under a 10-year agreement. These interconnect lines will allow us to eliminate the sale of gas oil at a discount to WTI under our 5-year gas oil off take agreement with a third party, optimize gasoline blending, increase our utilization of better process technology, improve yields and reduce operating costs. HEP is currently constructing five additional interconnect pipelines and we are currently negotiating terms for a long-term agreement with HEP to transfer intermediate products via these pipelines that will commence upon completion of the project. Also, as part of the integration, we are expanding the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We expect to complete the integration projects in the second quarter of 2011.

The combined Tulsa Refinery facilities also will be required to comply with MSAT2 regulations in order to meet new federal benzene reduction requirements for gasoline. We have elected to largely use existing equipment at the Tulsa Refinery east facility to split reformate from reformers at both west and east facilities and install a new benzene saturation unit to achieve the required benzene reduction at an estimated cost of $28.5 million. We will be required to buy benzene credits to get the gasoline pool below 0.62% by volume until this project is complete, as required by law, beginning in 2011. There is an additional requirement to meet 1.3% benzene levels on an annual average beginning in July 2012. We expect to complete this project well before then.

Our consent decree with the EPA requires recovery of sulfur from the refinery fuel gas system and the shutdown or replacement of two low pressure boilers at the Tulsa Refinery west facility by the end of 2013. We have previously estimated a cost of $20 million to meet these requirements but our Board of Directors have approved a larger project for $44 million which would meet these requirements as well as increase our ability to run additional lower priced sour crudes at the Tulsa Refinery east facility. Also, we are evaluating the best solution to the low pressure boiler issue. In addition to the consent decree requirements, flare gas recovery and coker blowdown modifications are required to comply with new flare regulations at an estimated cost of $10 million.

Holly Asphalt Company

We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. We have four manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico, Artesia, New Mexico and Lubbock, Texas. Our Albuquerque, Artesia and Lubbock facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo and Tulsa Refineries and third-party suppliers. Our Lubbock facility is leased under a lease agreement expiring December 31, 2011. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our Navajo, Woods Cross and Tulsa Refineries and third-party suppliers. We sell additional modified asphalt and commodity emulsions into the Arizona and California markets through a third-party processing agreement in Phoenix. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.

Our total capital budget for Holly Asphalt for 2011 is $3.6 million.

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We also completed our asphalt tankage project at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico in November 2010. This project consisted of asphalt tank additions and the upgrade of our rail loading facilities at the Navajo Refinery Artesia facility.

UNEV Pipeline

Under a definitive agreement with Sinclair, we are jointly building 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. Under the agreement, we own a 75% interest in the joint venture pipeline with Sinclair, our joint venture partner, owning the remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD (based on gasoline equivalents), with the capacity for further expansion to 120,000 BPD. The current total cost of the pipeline project including terminals is expected to be approximately $325 million, with our share of the cost totaling $244 million. This project includes the construction of ethanol blending and storage facilities at the Cedar City terminal. The pipeline is in the final construction phase and is expected to be mechanically complete in the second quarter of 2011.

In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 BPD of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

HOLLY ENERGY PARTNERS, L.P.

In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that also trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in west Texas, New Mexico, Utah, Idaho, Arizona and Oklahoma.

HEP owns and operates a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah and distribution terminals and refinery tankage in Texas, New Mexico, Arizona, Utah, Oklahoma, Idaho and Washington. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals; therefore, it is not directly exposed to changes in commodity prices.

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, HEP acquired from us certain storage assets for $93 million, consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa Refinery east facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, HEP acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at what is now our Tulsa Refinery east facility for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million.

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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 Refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa Refinery 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 million. Results of operations of Rio Grande are presented in discontinued operations.

Transportation Agreements

Agreements with HEP

HEP serves our refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

	•		HEP PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets that we contributed to HEP upon its initial public offering in 2004);

	•		HEP IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines sold to HEP in 2005 and 2009);

	•		HEP CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets sold to HEP in 2008);

	•		HEP PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired in 2009 and 2010);

	•		HEP RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline sold to HEP in 2009);

	•		HEP ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities sold to HEP in 2009);

	•		HEP NPA (natural gas pipeline throughput agreement expiring in 2024); and

	•		HEP ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility sold to HEP in March 2010).

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. These minimum annual payments are adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in PPI or Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the HEP IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC

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adjustment factor that is reviewed periodically. Following the July 1, 2010 PPI adjustment, these agreements will result in minimum annualized payments to HEP of $133 million for the twelve months ended June 30, 2011.

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

Agreement with Alon

HEP also has a 15-year pipelines and terminals agreement with Alon expiring in 2020 (the “Alon PTA”), 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.

HEP also has a capacity lease agreement with Alon under which Alon is leased space on HEP’s Orla to El Paso pipeline for the shipment of up to 17,500 barrels of refined product per day. The terms under this agreement expire beginning in 2012 through 2018.

As of December 31, 2010, HEP’s contractual minimum revenues under long-term service agreements are as follows:


	Minimum Annualized
	Commitment
Agreement	(In millions)		Year of Maturity		Contract Type
HEP PTA⁽¹⁾		$ 43.7		2019	Minimum revenue commitment
HEP IPA⁽¹⁾		20.7		2024	Minimum revenue commitment
HEP CPTA⁽¹⁾		28.4		2023	Minimum revenue commitment
HEP PTTA⁽¹⁾		27.2		2024	Minimum revenue commitment
HEP RPA⁽¹⁾		9.2		2024	Minimum revenue commitment
HEP ETA⁽¹⁾		2.7		2024	Minimum revenue commitment
Holly ATA⁽¹⁾		0.5		2025	Minimum revenue commitment
Holly NPA⁽¹⁾		0.6		2024	Minimum revenue commitment
Alon PTA⁽²⁾		22.7		2020	Minimum volume commitment
Alon capacity lease⁽²⁾		6.6	Various		Capacity lease


Total		$162.3


(1)		HEP’s revenue under these transportation agreements with us represents intercompany revenue and is eliminated in our consolidated financial statements.

(2)		Minimum annual revenues attributable to long-term service contracts with unaffiliated parties are $29.3 million.

As of December 31, 2010, HEP’s assets include:

Pipelines

	•		approximately 820 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico;

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

	•		three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico;

	•		approximately 960 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery;

	•		approximately 10 miles of crude oil and refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah; and

	•		gasoline and diesel connecting pipelines that support our Tulsa Refinery east facility.

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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 1,000,000 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 480,000 barrels, that are integrated with HEP’s refined product pipelines that serve Alon’s Big Spring, Texas refinery;

	•		a refined product truck loading rack facility at each of our Navajo and Woods Cross Refineries, an asphalt truck loading rack at our Navajo Refinery Lovington facility, refined product and lube oil rail loading racks and a lube oil truck loading rack at our Tulsa Refinery west facility and a refined product, asphalt and LPG truck loading rack, a truck unloading rack and a rail loading rack at our Tulsa Refinery east facility;

	•		a Roswell, New Mexico jet fuel terminal leased through September 2011;

	•		on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries having an aggregate storage capacity of approximately 600,000 barrels; and

	•		on-site refined product tankage at our Tulsa Refinery having an aggregate storage capacity of approximately 3,400,000 barrels.

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

Capital Improvement Projects

HEP’s capital budget for 2011 is comprised of $5.8 million for maintenance capital expenditures and $20.1 million for expansion capital expenditures.

As described under our Tulsa Refinery integration project, HEP is currently constructing five interconnecting pipelines between our Tulsa east and west refining facilities. The project is expected to cost approximately $28 million with completion in the second quarter of 2011. We are currently negotiating terms for a long-term agreement with HEP to transfer intermediate products via these pipelines that will commence upon completion of the project.

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

We lease our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires in June 2011 and requires lease payments of approximately $115,000 per month plus certain operating expenses. Prior to expiration, we will be relocating our corporate offices to a nearby office building complex, also located in Dallas, Texas. The lease for our new office 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, 2010, we had 1,661 employees, of which 353 are currently covered by collective bargaining agreements. We consider our employee relations to be good. We have collective bargaining agreements for certain of our Woods Cross Refinery employees that expire in 2012 and agreements with certain of our Navajo Refinery Artesia and Lovington facility employees that expire in 2016.

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Regulation

Refinery and pipeline operations are subject to federal, state and local laws regulating the discharge of matter 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 operations, 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, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.

Our operations and many of the products we manufacture are subject to certain specific requirements of the Federal Clean Air Act (“CAA”) and related state and local regulations. The CAA contains provisions that require capital expenditures for the installation of certain air pollution control devices at our refineries. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules, may necessitate additional expenditures in future years.

Under the CAA, the EPA has the authority to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. In June 2004, the EPA issued new regulations limiting emissions from diesel fuel powered engines used in non-road activities such as mining, construction, agriculture, railroad and marine and simultaneously limiting the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. Our Navajo and Woods Cross Refineries as well as our Tulsa Refinery east facility produce non-road and highway diesel that meets the ultimate 15 PPM sulfur standard. Currently, however, our Tulsa Refinery west facility does not produce diesel that meets that standard. Under our Tulsa Refinery integration project, we will be expanding our Tulsa Refinery east facility’s diesel hydrotreater unit, enabling it to process all diesel fuel produced at the Tulsa Refinery.

Additionally, as of January 1, 2011 we are required to meet another EPA regulation limiting the average sulfur content in gasoline to 30 PPM. We plan to meet this requirement using previously internally generated sulfur credits.

Also as of January 1, 2011, we are required to comply with the EPA’s new MSAT2 regulations on gasoline that impose reductions in the benzene content of our produced gasoline. We plan to purchase benzene credits to meet these requirements. Our planned capital projects will reduce the amount of benzene credits that we need to purchase and we could implement additional benzene reduction projects to completely eliminate our benzene credit purchase requirements if we can justify such a project from a cost benefit standpoint. In addition, the renewable fuel standards will mandate the blending of prescribed percentages of renewable fuels (e.g., ethanol and biofuels) into our produced gasoline and diesel. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may cause us to make substantial capital expenditures as well as the purchase of credits at significant cost, to enable our refineries to produce products that meet applicable requirements.

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 strict conformance with permits, such as pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.

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

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of

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persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. 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 require cleanup under Superfund.

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, 2010 we had an accrual of $26.2 million related to such environmental liabilities of which $20.4 million was classified as long-term.

We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries, including those discussed above. Current and future environmental regulations are 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.

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.

Insurance

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

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

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Item 1A. Risk Factors

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

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

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

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

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

One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that

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can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets such as our UNEV Pipeline joint venture, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada that is currently under construction and in which our subsidiary owns a 75% interest. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including:

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

	•		compliance with or liability under environmental regulations; unplanned increases in the cost of construction materials or labor;

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

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

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

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

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

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

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

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

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

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

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

	•		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 in achieving anticipated operational improvements;

	•		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.

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

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

As of December 31, 2010, the principal amount of our total consolidated outstanding debt was $833 million, including $494 million of HEP debt.

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

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

Although the domestic capital markets have shown signs of improvement in recent months, global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, continued high unemployment, geopolitical issues and the current weak economic conditions. In addition, the fixed-income markets have experienced periods of extreme volatility that have 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 those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

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

Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements.

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

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

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

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

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

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

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

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires

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a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010.

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

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

In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition and results of operations.

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

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

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

In addition, we expect to execute turnarounds at our refineries, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform

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maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime.

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

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life or destruction of property, injury, or extensive property damage, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.

We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

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

We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater

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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 addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be material adverse effects on our business, financial condition and results of operations.

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

Portions of our operations in the areas we operate may be impacted by competitors’ plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability.

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

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

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. For example, we face certain challenges as we continue to integrate the operations of the Tulsa facilities, purchased in 2009, into our business. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of the acquisitions we recently completed or as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, including the assets and businesses we acquired in 2009. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.

Our proposed “merger of equals” business combination with Frontier is subject to a number of conditions beyond our control. Failure to complete the Merger within the expected timeframe or at all could adversely affect our stock price and our future business and financial results.

Our proposed “merger of equals” business combination with Frontier is subject to a number of conditions beyond our control that may prevent, delay or otherwise materially adversely affect the Merger’s completion, including approval of our stockholders and of Frontier’s stockholders and the expiration or termination of applicable waiting periods under U.S. antitrust laws and various approvals or consents that must be obtained from regulatory authorities or third parties. We cannot predict whether and when these conditions will be satisfied. Any delay in completing the Merger could cause the combined company not to realize some or all of the synergies expected to be achieved. We

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will also incur substantial transaction costs whether or not the merger is completed. Any failure to complete the merger could have a material adverse effect on our stock price and our future business and financial results.

The anticipated benefits of our Merger may not be realized fully or at all or may take longer to realize than expected.

The Merger involves the integration of two companies that have previously operated independently. After the Merger, the two companies will devote significant management attention and resources to integrating the two companies. Delays in this process could adversely affect the combined company’s business, financial results, financial condition and stock price. Even if we are able to integrate our business operations successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect from this integration or that these benefits will be achieved within the anticipated time frame.

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

We are completing major capital investment programs at both our Navajo and Woods Cross Refineries. At the Tulsa Refinery we have various projects planned to integrate the two facilities to fully utilize their capabilities. All three refineries also have various environmental compliance related projects.

The installation of new equipment and the revamp of key existing equipment involve significant risks and uncertainties, including the following:

	•		Equipment may not perform at expected throughput levels,

	•		Actual yields or product quality may differ from design,

	•		Actual operating costs may be higher than expected,

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

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

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

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

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

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

Other refined product transportation pipelines currently supply our existing markets or could potentially supply our existing markets in the future.

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

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

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

We currently own a 34% 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 Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. 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 and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2025. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to:

	•		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.

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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.”

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

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

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

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

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

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

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

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

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

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

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

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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.

We may be unable to pay future dividends.

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

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

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

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

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

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations. Failure of our products to meet required specifications could result in product liability claims from our shippers and customers arising from contaminated or off-specification commingled pipelines and storage tanks and/or defective quality fuels.

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

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

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

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

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We generally purchase crude oil for our refineries with cash generated from our operations. If the price of crude oil increases significantly, we may not have sufficient cash flow or borrowing capacity, and may not be able to sufficiently increase borrowing capacity, under our existing credit facilities to purchase enough crude oil to operate our refineries at desired capacity. Our failure to operate our refineries at desired capacity could have a material adverse effect on our business, financial condition and results of operations. We also have significant long-term needs for cash, including those to support our expansion and upgrade plans, as well as for regulatory compliance. If credit markets tighten, it may become more difficult to obtain cash from third party sources. If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with regulatory deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect and we could be subject to regulatory action.

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

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

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

The operating and financial restrictions and covenants in our credit facilities and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our revolving credit facility imposes usual and customary requirements for this type of credit facility, including: (i) maintenance of certain levels of interest coverage and leverage ratios; (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 discontinues 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.

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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, 2010, approximately 21% of our employees were represented by labor unions under collective bargaining agreements with various expiration dates. Effective February 1, 2009, a new agreement was reached with the United Steelworkers which applies to approximately 7% of our employees, which agreement will now expire on January 31, 2012. As of December 31, 2010, approximately 14% of our employees were represented by labor unions under a collective bargaining agreement that expires in 2016. 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.

Uncertainty about the Merger and diversion of management could harm us or the combined company, whether or not the Merger is completed.

The announcement of the Merger could result in current and prospective employees experiencing uncertainty about their future with us or the combined company. These uncertainties may impair our ability to retain, recruit or motivate key personnel. Completion of the Merger will also require a significant amount of time and attention from our management. The diversion of management’s attention away from ongoing operations could adversely affect our business relationships. Even if the merger is consummated, integration of operations will require substantial time after consummation of the Merger, and the combined company may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.

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

We have benefit obligations in connection with our noncontributory defined benefit pension plans that provided retirement benefits for substantially all of our employees. However, effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an employee not covered by a collective bargaining agreement was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen. We expect to contribute between zero to $10 million to the retirement plan in 2011. Future adverse changes in the financial markets could result in significant charges to stockholders’ equity and additional significant increases in future pension expense and funding requirements.

We also have benefit obligations in connection with our unfunded postretirement health care plans that provide health care benefits as part of the voluntary early retirement program offered to eligible employees. As part of the early retirement program, we allow qualified retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. As of December 31, 2010, the total accumulated postretirement benefit obligation under our postretirement medical plans was $7.9 million. Increased participation in this program and/or increasing medical costs may affect our ability to pay required health care benefits causing us to have to divert funds away from other areas of the business to pay their costs.

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

A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the products loaded at our loading racks. If our quality control measures were to fail, off specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages

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caused by the off specification fuel or could impact our ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

Item 3. Legal Proceedings

Commitment and Contingency Reserves

When deemed necessary, we 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.

SFPP Litigation

a. The Early Complaint Cases

In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the FERC in proceedings brought by us and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona on SFPP’s East Line. The Court of Appeals in its May 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated as limited partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. The case was remanded to FERC and consolidated with other cases that together addressed SFPP’s rates for the period from January 1992 through May 2006. In 2003 we received an initial payment of $15.3 million from SFPP as reparations for the period from 1992 through July 2000. On April 16, 2010, a settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved the settlement on May 28, 2010. Pursuant to the settlement, we received an additional settlement payment of $8.6 million. This settlement finally resolves the amount of additional payments SFPP owes us for the period January 1992 through May 2006.

b. Other Settlements

We and other shippers also engaged in settlement discussions with SFPP relating to East Line service in the FERC proceedings that address periods after May 2006. A partial settlement regarding the East Line’s Phase I expansion rates covering the period June 2006 through November 2007, which became final in February 2008, resulted in a payment from SFPP to us of $1.3 million in April 2008. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement regarding the East Line’s Phase II expansion rates covering the period from December 2007 through November 2010. The FERC approved the settlement on January 29, 2009. The settlement reduced SFPP’s current rates and required SFPP to make additional payments to us of $2.9 million, which were received on May 18, 2009.

c. The Latest Rate Proceeding

On June 2, 2009, SFPP notified us that it would terminate the October 22, 2008 settlement, as provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial rate increases for East Line service to become effective September 1, 2009. We and several other shippers filed protests at the FERC, challenging the

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rate increase and asking the FERC to suspend the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending the effective date of the rate increase until January 1, 2010, on which date the rate increase was placed into effect subject to refund, and setting the rate increase for a full evidentiary hearing. The hearing was held from June 29, 2010 to August 2, 2010. On September 15, 2010, the FERC approved an interim partial settlement pursuant to which SFPP reduced its rates for the East Line service, effective September 1, 2010. The rates placed in effect on January 1, 2010, and the lower rates put into effect on September 1, 2010, remain subject to refund subject to the outcome of the evidentiary hearing. On February 10, 2011, the Administrative Law Judge that presided over the evidentiary hearing issued an initial decision holding that certain elements of SFPP’s rate increases are unjust and unreasonable. The initial decision is subject to review by the FERC and the courts. We are not in a position to predict the ultimate outcome of the rate proceeding.

Cut Bank Hill Environmental Claims

Prior to the sale by Holly Corporation of the Montana Refining Company (“MRC”) assets in 2006, MRC, along with other companies was the subject of several environmental claims at the Cut Bank Hill site in Montana. These claims include: (1) a U.S. Environmental Protection Agency administrative order requiring MRC and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against MRC and other companies for response costs of $0.3 million in connection with its cleanup efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of Environmental Quality (“MDEQ”) directing MRC and other companies to complete a remedial investigation and a request by the MDEQ that MRC and other companies pay $0.2 million to reimburse the State’s costs for remedial actions. MRC has denied responsibility for the requested EPA and the MDEQ cleanup actions and the MDEQ and Coast Guard response costs.

Navajo Tank Fire

On March 2, 2010, a tank caught fire while under construction. At the time of the incident, four individuals were working on top of the tank. These individuals were all employees of a third-party contractor who was placing insulation on the tank. Two individuals sustained injuries and two individuals died as a result of the incident. Two wrongful death lawsuits and two personal injury lawsuits seeking damages, including punitive damages, were filed on behalf of the estates of the two deceased workers and on behalf of the two survivors in state court in Dallas County, Texas (two lawsuits) and state court in Eddy County, New Mexico (two lawsuits). The two Texas cases are set for trial in May of 2011. One of the cases in New Mexico is set for trial in March of 2012. At the date of this report, it is not possible to predict the likely outcome of this litigation. This matter is being reported due to the serious nature of the injuries. Because of our insurance coverage, the total cost to the Company for these cases is not expected to be material.

New Mexico OHSB Complaint — Navajo Tank Fire

On March 3, 2010, the New Mexico Occupational Health and Safety Bureau (“OHSB”), the New Mexico regulatory agency responsible for enforcing certain state occupational health and safety regulations, which are identical to Federal Occupational Safety and Health Administration (“OSHA”) regulations, commenced an inspection in relation to the tank fire that took place on March 2, 2010 at the Navajo facility in Artesia, New Mexico. On August 31, 2010, OHSB issued two citations to Navajo Refining Company, LLC (“Navajo”), alleging 10 willful violations and 1 serious violation of various construction safety standards. OHSB proposed penalties in the amount of $0.7 million. Navajo filed a notice of contest, challenging the citations. An informal administrative review of the citations took place on November 17, 2010, at which time counsel for the parties discussed possible settlement options. The parties were unable to reach an agreement. Thus, OHSB filed an administrative complaint with New Mexico’s Occupational Health and Safety Review Commission (“OSHRC”) on December 20, 2010. Navajo will challenge the citations before the OSHRC, and filed its answer to the complaint on January 6, 2011. The parties have agreed to a discovery schedule and jointly requested a hearing date to commence no sooner than September 5, 2011.

OSHA Inspections — Tulsa Refinery

In June 2007, OSHA announced a national emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As part of the NEP, OSHA conducted an inspection of Sinclair Tulsa Refining Company’s

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(“Sinclair Tulsa”) refinery in Tulsa, Oklahoma (our Tulsa Refinery east facility) from February 4, 2009 through August 3, 2009. On August 4, 2009, OSHA issued two citations to Sinclair Tulsa, alleging 51 serious violations and 1 willful violation of various safety standards including the Process Safety Management (“PSM”) standard and the General Duty Clause. OSHA proposed penalties totaling $0.2 million. Sinclair filed a notice of contest, challenging the citations.

Our subsidiary, Holly Refining & Marketing — Tulsa LLC (“HRM-Tulsa”), entered into an Asset Sale & Purchase Agreement (the “Agreement”) with Sinclair Tulsa dated October 19, 2009 to acquire the Tulsa Refinery east facility, and the sale closed on December 1, 2009. HRM-Tulsa intervened in the case against Sinclair Tulsa pending before the OSHRC shortly after the sale closed. Under the terms of the Agreement, Sinclair retains responsibility for defending the OSHA citations and paying any penalties, and HRM-Tulsa has the discretion to select the means and methods of improving the PSM program. HRM-Tulsa has evaluated the feasibility of various PSM program improvements and developed a plan to implement a number of safety enhancements at the Tulsa Refinery east facility. HRM-Tulsa management presented its safety improvement plan to OSHA and OSHA approved the plan. HRM-Tulsa and OSHA negotiated a settlement agreement which memorializes OSHA’s approval of the safety improvement plan. The settlement agreement between HRM-Tulsa and OSHA was filed with the OSHRC on August 11, 2010. On August 23, 2010, the OSHRC entered an order approving both the settlement agreement between Sinclair Tulsa and OSHA and the agreement between HRM-Tulsa and OSHA.

OSHA conducted an inspection of our Tulsa Refinery west facility from January 20, 2010 through June 9, 2010. On July 12, 2010, OSHA issued a citation, alleging 10 serious violations of various safety standards, including the PSM standard. OSHA proposed penalties totaling $57,150. HRM Tulsa filed a notice of contest, and challenged each citation item. The matter has been assigned to Judge Patrick B. Augustine. A pretrial conference took place on November 3, 2010, at which Judge Augustine established March 11, 2011 as the deadline for close of discovery and scheduled the hearing to take place from April 11 — 15, 2011.

OSHA began the NEP inspection of our Tulsa Refinery west facility on September 14, 2010. The inspection is ongoing.

Discharge Permit Appeal — Tulsa Refinery West Facility

Our subsidiary, HRM Tulsa is party to parallel Oklahoma administrative and state district court proceedings involving a challenge to the terms of the Oklahoma Department of Environmental Quality (“ODEQ”) permit that governs the discharge of industrial wastewater from our Tulsa Refinery west facility. Pursuant to a settlement agreement between HRM Tulsa and ODEQ, both proceedings have been stayed to allow ODEQ to issue a revised permit that modifies the existing permit’s requirements for toxicity testing and for managing storm flows. The parties are now in discussions regarding the appropriate changes in the permit language to accomplish these modifications. Once agreed-upon revisions are made and become effective, both proceedings will be dismissed. Any changes to refinery processes that result from the permit revisions will be subject to regulatory review and approval. Accordingly, it is not possible to estimate the costs of compliance with the new permit provisions at this time.

Unclaimed Property Audit

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

Other

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

Item 4. (Removed and Reserved)

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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 “HOC.” 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:


							Trading
Years Ended December 31,	High		Low		Dividends		Volume
2010
Fourth quarter	$	41.38	$	28.19	$	0.15		36,902,900
Third quarter	$	29.86	$	24.35	$	0.15		37,493,600
Second quarter	$	30.57	$	23.32	$	0.15		63,314,200
First quarter	$	30.86	$	25.13	$	0.15		47,712,400

2009
Fourth quarter	$	33.53	$	23.57	$	0.15		52,039,700
Third quarter	$	26.22	$	16.71	$	0.15		50,535,600
Second quarter	$	31.63	$	17.23	$	0.15		73,542,100
First quarter	$	27.42	$	18.15	$	0.15		85,489,800

As of February 8, 2011, we had approximately 20,900 stockholders, including beneficial owners holding shares in street name.

We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors. Our credit agreement and senior notes limit the payment of dividends. See Note 12 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”

There were no common stock repurchases during the fourth quarter of 2010.

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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,
	2010			2009			2008			2007			2006
	(In thousands, except per share data)
FINANCIAL DATA⁽¹⁾
For the period
Sales and other revenues	$	8,322,929		$	4,834,268		$	5,860,357		$	4,791,742		$	4,023,217
Income from continuing operations before income taxes		192,363			43,803			187,746			499,444			383,501
Income tax provision		59,312			7,460			64,028			165,316			136,603

Income from continuing operations		133,051			36,343			123,718			334,128			246,898
Income from discontinued operations, net of taxes⁽²⁾		—			16,926			2,918			—			19,668

Net income		133,051			53,269			126,636			334,128			266,566
Less net income attributable to noncontrolling interest		29,087			33,736			6,078			—			—


Net income attributable to Holly Corporation Stockholders	$	103,964		$	19,533		$	120,558		$	334,128		$	266,566


Earnings per share attributable to Holly Corporation stockholders — basic	$	1.95		$	0.39		$	2.40		$	6.09		$	4.68

Earnings per share attributable to Holly Corporation stockholders — diluted	$	1.94		$	0.39		$	2.38		$	5.98		$	4.58

Cash dividends declared per common share	$	0.60		$	0.60		$	0.60		$	0.46		$	0.29

Average number of common shares outstanding:
Basic		53,218			50,418			50,202			54,852			56,976
Diluted		53,609			50,603			50,549			55,850			58,210

Net cash provided by operating activities	$	283,255		$	211,545		$	155,490		$	422,737		$	245,183
Net cash provided by (used for) investing activities	$	(213,232	)	$	(534,603	)	$	(57,777	)	$	(293,057	)	$	35,805
Net cash provided by (used for) financing activities	$	34,482		$	406,849		$	(151,277	)	$	(189,428	)	$	(175,935	)

At end of period
Cash, cash equivalents and investments in marketable securities	$	230,444		$	125,819		$	94,447		$	329,784		$	255,953
Working capital	$	313,580		$	257,899		$	68,465		$	216,541		$	240,181
Total assets	$	3,701,475		$	3,145,939		$	1,874,225		$	1,663,945		$	1,237,869
Total debt, including short-term⁽³⁾	$	810,561		$	707,458		$	370,914		$	—		$	—
Total equity	$	1,288,139		$	1,207,781		$	936,332		$	602,127		$	466,094


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

(2)		On December 1, 2009, HEP sold its 70% interest in Rio Grande. Results of operations of Rio Grande that were previously reported in operations are presented in discontinued operations. For the year ended December 31, 2006, our discontinued operations were attributable to our Montana refinery that was sold in March 2006.

(3)		Includes total HEP debt of $482.3 million, $379.2 million and $370.9 million, respectively, which is non-recourse to Holly Corporation.

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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 Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of HEP effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions or obligations between HEP and Holly Corporation 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 Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

OVERVIEW

We are principally an independent petroleum refiner operating three refineries in Artesia and Lovington, New Mexico (operated as one refinery), Woods Cross, Utah and Tulsa, Oklahoma. As of December 31, 2010, our refineries had a combined crude capacity of 256,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2010, we also owned a 34% interest in HEP, a consolidated VIE, which owns and operates pipeline and terminalling assets.

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel, jet fuel and specialty and modified asphalt in markets in the Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. We also produce specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. Sales and other revenues from continuing operations and net income attributable to Holly Corporation stockholders were $8,322.9 million and $104 million, $4,834.3 million and $19.5 million, and $5,860.4 million and $120.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses were $8,059.9 million, $4,754 million and $5,664.7 million for the years ended December 31, 2010, 2009 and 2008, respectively.

On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco for $157.8 million including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America.

On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BPSD refinery from Sinclair also located in Tulsa, Oklahoma for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The refinery produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.

Separately, HEP, also a party to the December 1, 2009 transaction with Sinclair, acquired certain logistics and storage assets located at the Tulsa Refinery east facility. See “Holly Energy Partners, L.P. — 2009 Acquisitions” under Items 1 and 2, “Business and Properties” for additional information on this transaction as well as HEP’s 2010 and other 2009 asset acquisitions from us.

Also on December 1, 2009, HEP sold its 70% interest in Rio Grande to a subsidiary of Enterprise Products Partners LP for $35 million. Results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.

On February 29, 2008, we sold certain crude pipelines and tankage assets to HEP for $180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico and crude oil and product pipelines that support our refinery in Woods Cross, Utah. HEP is a VIE as defined under GAAP. Under GAAP, HEP’s purchase 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

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in HEP exceeded 50%. Therefore, we reconsolidated HEP effective March 1, 2008. Intercompany transactions with HEP are eliminated in our consolidated financial statements.

Recent Developments

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination of us and Frontier. Subject to the terms and conditions of the merger agreement which has been approved unanimously by both our and Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of Holly common stock for each share of Frontier common stock if the Merger is completed. See “Recent Developments” in Company Overview section under Items 1 and 2, “Business and Properties” for additional information on the Merger.

RESULTS OF OPERATIONS

Financial Data


	Years Ended December 31,
	2010			2009			2008
	(In thousands, except per share data)
Sales and other revenues	$	8,322,929		$	4,834,268		$	5,860,357
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		7,367,149			4,238,008			5,280,699
Operating expenses (exclusive of depreciation and amortization)		504,414			356,855			265,705
General and administrative expenses (exclusive of depreciation and amortization)		70,839			60,343			55,278
Depreciation and amortization		117,529			98,751			62,995

Total operating costs and expenses		8,059,931			4,753,957			5,664,677

Income from operations		262,998			80,311			195,680
Other income (expense):
Equity in earnings of SLC Pipeline		2,393			1,919			—
Interest income		1,168			5,045			10,797
Interest expense		(74,196	)		(40,346	)		(23,955	)
Acquisition costs — Tulsa refineries		—			(3,126	)		—
Impairment of equity securities		—			—			(3,724	)
Gain on sale of Holly Petroleum, Inc.		—			—			5,958
Equity in earnings of HEP		—			—			2,990

		(70,635	)		(36,508	)		(7,934	)

Income from continuing operations before income taxes		192,363			43,803			187,746
Income tax provision		59,312			7,460			64,028

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

Net income		133,051			53,269			126,636
Less net income attributable to noncontrolling interest		29,087			33,736			6,078

Net income attributable to Holly Corporation stockholders	$	103,964		$	19,533		$	120,558


Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	103,964		$	15,209		$	119,206
Income from discontinued operations		—			4,324			1,352

Net income	$	103,964		$	19,533		$	120,558


Earnings per share attributable to Holly Corporation stockholders — basic:
Income from continuing operations	$	1.95		$	0.30		$	2.37
Income from discontinued operations		—			0.09			0.03

Net income	$	1.95		$	0.39		$	2.40


Earnings per share attributable to Holly Corporation stockholders — diluted:
Income from continuing operations	$	1.94		$	0.30		$	2.36
Income from discontinued operations		—			0.09			0.02

Net income	$	1.94		$	0.39		$	2.38


Cash dividends declared per common share	$	0.60		$	0.60		$	0.60


Average number of common shares outstanding:
Basic		53,218			50,418			50,202
Diluted		53,609			50,603			50,549

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Balance Sheet Data


	December 31,
	2010		2009
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	230,444	$	125,819
Working capital	$	313,580	$	257,899
Total assets	$	3,701,475	$	3,145,939
Long-term debt — Holly Corporation	$	328,290	$	328,260
Long-term debt — Holly Energy Partners	$	482,271	$	379,198
Total equity	$	1,288,139	$	1,207,781


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

Other Financial Data


	Years Ended December 31,
	2010			2009			2008
				(In thousands)
Net cash provided by operating activities	$	283,255		$	211,545		$	155,490
Net cash used for investing activities	$	(213,232	)	$	(534,603	)	$	(57,777	)
Net cash provided by (used for) financing activities	$	34,482		$	406,849		$	(151,277	)
Capital expenditures	$	213,232		$	302,551		$	418,059
EBITDA from continuing operations⁽¹⁾	$	353,833		$	156,721		$	259,387


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

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


	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Sales and other revenues
Refining⁽¹⁾	$	8,287,000		$	4,789,821		$	5,837,449
HEP⁽²⁾		182,114			146,561			94,439
Corporate and other		415			(636	)		2,641
Eliminations		(146,600	)		(101,478	)		(74,172	)

Consolidated	$	8,322,929		$	4,834,268		$	5,860,357


Operating income (loss)
Refining⁽¹⁾	$	242,466		$	71,281		$	210,252
HEP⁽²⁾		92,386			70,373			37,082
Corporate and other		(69,654	)		(60,239	)		(51,654	)
Eliminations		(2,200	)		(1,104	)		—

Consolidated	$	262,998		$	80,311		$	195,680

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

(2)		The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude gathering pipelines and refinery tankage in Texas, New Mexico, Oklahoma and Utah, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma and Washington. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through its pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Additionally, HEP owns a 25% interest in the SLC Pipeline that services refineries in the Salt Lake City, Utah area. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations.

Refining Operating Data

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


	Years Ended December 31,
	2010			2009			2008
*Consolidated*
Crude charge (BPD)⁽¹⁾		221,440			142,430			100,680
Refinery throughput (BPD)⁽²⁾		234,910			154,940			114,130
Refinery production (BPD)⁽³⁾		225,980			151,420			110,850
Sales of produced refined products (BPD)		228,140			151,580			111,950
Sales of refined products (BPD)⁽⁴⁾		232,100			155,820			120,750

Refinery utilization⁽⁵⁾		86.5	%		78.9	%		89.7	%

Average per produced barrel⁽⁶⁾
Net sales	$	91.06		$	74.06		$	108.83
Cost of products⁽⁷⁾		82.27			66.85			97.87

Refinery gross margin		8.79			7.21			10.96
Refinery operating expenses⁽⁸⁾		5.08			5.24			5.14

Net operating margin	$	3.71		$	1.97		$	5.82


Refinery operating expenses per throughput barrel	$	4.94		$	5.12		$	5.05


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

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

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

(4)		Includes refined products purchased for resale.

(5)		Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 111,000 BPSD to 116,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion). During 2009, we increased our consolidated crude capacity by 15,000 BPSD effective April 1, 2009 (our Navajo Refinery expansion), by 85,000 BPSD effective June 1, 2009 (our Tulsa Refinery west facility acquisition) and by 40,000 BPSD effective December 1, 2009 (our Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD.

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

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

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

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

Summary

Net income attributable to Holly Corporation stockholders for the year ended December 31, 2010 was $104 million ($1.95 per basic and $1.94 per diluted share) an $84.4 million increase compared to $19.5 million ($0.39 per basic and diluted share) for the year ended December 31, 2009. Net income increased due principally to increased sales volumes of produced refined products combined with higher refinery gross margins during 2010. Overall refinery gross margins for the year ended December 31, 2010 were $8.79 per produced barrel compared to $7.21 for the year ended December 31, 2009.

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

Sales and Other Revenues

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

Cost of Products Sold

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

Gross Refinery Margins

Gross refining margin per produced barrel increased 22% from $7.21 for the year ended December 31, 2009 to $8.79 for the year ended December 31, 2010, due to an increase in the average sales price we received per produced barrel sold, partially offset by an increase in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and costs of products purchased.

Operating Expenses

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

General and Administrative Expenses

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

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Depreciation and Amortization Expenses

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

Interest Income

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

Interest Expense

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

Income Taxes

Income taxes increased from $7.5 million for the year ended December 31, 2009 to $59.3 million for the year ended December 31, 2010 due to significantly higher pre-tax earnings for the year ended December 31, 2010 compared to 2009. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 30.8% for the year ended December 31, 2010 compared to 17% for the year ended December 31, 2009. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation. Our actual tax rate for income tax purposes did not increase.

Discontinued Operations

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

Results of Operations — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Summary

Net income attributable to Holly Corporation stockholders for the year ended December 31, 2009 was $19.5 million ($0.39 per basic and diluted share) a $101 million decrease compared to $120.6 million ($2.40 per basic and $2.38 per diluted share) for the year ended December 31, 2008. Net income decreased due principally to an overall decrease in refined gross margins in the second half of 2009. Overall refinery gross margins for the year ended December 31, 2009 were $7.21 per produced barrel compared to $10.96 for the year ended December 31, 2008.

Overall production levels for the year ended December 31, 2009 increased by 37% over 2008 due to production from our Tulsa Refinery facilities acquired in June and December 2009 and production gains resulting from our recent Navajo and Woods Cross Refinery capacity expansions. Also impacting production levels was scheduled downtime for major maintenance turnarounds at the Navajo Refinery in the first quarter of 2009 and the Woods Cross Refinery in the third quarter of 2008. During the first quarter of 2009, we timed our Navajo Refinery turnaround to coincide with the completion of its 15,000 BPSD capacity expansion, increasing refining capacity to 100,000 BPSD.

Sales and Other Revenues

Sales and other revenues from continuing operations decreased 18% from $5,860.4 million for the year ended December 31, 2008 to $4,834.3 million for the year ended December 31, 2009, due principally to significantly lower refined product sales prices, partially offset by the effects of a 29% increase in volumes of refined products sold. The average sales price we received per produced barrel sold decreased 32% from $108.83 for the year ended

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December 31, 2008 to $74.06 for the year ended December 31, 2009. Additionally, direct sales of excess crude oil also decreased in 2009 compared to 2008. Sales and other revenues for the years ended December 31, 2009 and 2008, include $45.2 million and $19.3 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold decreased 20% from $5,280.7 million in 2008 to $4,238 million in 2009, due principally to the effects of significantly lower crude oil costs, partially offset by the effects of a 29% increase in volumes of refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place decreased 32% from $97.87 for the year ended December 31, 2008 to $66.85 for the year ended December 31, 2009.

Gross Refinery Margins

Gross refining margin per produced barrel decreased 34% from $10.96 for the year ended December 31, 2008 to $7.21 for the year ended December 31, 2009, due to a decrease in the average sales price we received per produced barrel sold, partially offset by the effects of a decrease in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and costs of products purchased.

Operating Expenses

Operating expenses, exclusive of depreciation and amortization increased 34% from $265.7 million for the year ended December 31, 2008 to $356.9 million for the year ended December 31, 2009, due principally to costs attributable to the operations of our Tulsa Refinery facilities acquired in June and December 2009 and the inclusion of HEP operating expense for a full twelve-month period in 2009 compared to ten months in 2008 due to our reconsolidation of HEP effective March 1, 2008. Additionally, there were certain increased costs at our existing facilities following the recently completed expansions, which were partially offset by lower utility costs. For the years ended December 2009 and 2008, operating expenses included $43.5 million and $33.4 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses

General and administrative expenses increased 9% from $55.3 million for the year ended December 31, 2008 to $60.3 million for the year ended December 31, 2009, due principally to costs associated with the support and integration of our Tulsa Refinery operations, increased payroll costs and increased professional fees and services. Additionally, general and administrative expenses for the years ended December 31, 2009 and 2008 include $5.3 million and $3.7 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 57% from $63 million for the year ended December 31, 2008 to $98.8 million for the year ended December 31, 2009. The increase was due principally to depreciation and amortization attributable to our Tulsa Refinery facilities, capitalized refinery improvement projects in 2008 and 2009 and the inclusion of HEP depreciation expense for a full twelve-month period during 2009 compared to ten months in 2008. For the years ended December 31, 2009 and 2008, depreciation and amortization expenses included $26.5 million and $18.4 million, respectively, in costs attributable to HEP operations.

Interest Income

Interest income for the year ended December 31, 2009 was $5 million compared to $10.8 million for the year ended December 31, 2008. The decrease was due principally to the effects of a decrease in cash balances and investments in marketable debt securities that was partially offset by interest on income tax refunds received in 2009.

Interest Expense

Interest expense was $40.3 million for the year ended December 31, 2009 compared to $24 million for the year ended December 31, 2008. The increase was due principally to interest attributable to increased long-term debt, including the Holly 9.875% Senior Notes issued in 2009, and the inclusion of HEP interest expense for a full twelve-

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month period during 2009 compared to ten months in 2008. For the years ended December 31, 2009 and 2008, interest expense included $23.8 million and $21.5 million, respectively, in costs attributable to HEP operations.

Acquisition Costs — Tulsa Refineries

During the year ended December 31, 2009, we incurred $3.1 million in acquisition costs related to our June 1, 2009 Tulsa Refinery west facility and our December 1, 2009 Tulsa Refinery east facility acquisitions.

Impairment of Equity Securities

For the year ended December 31, 2008, we recorded an impairment loss of $3.7 million that related to our 1,000,000 shares of Connacher common stock that we received in connection with our sale of the Montana refinery in 2006. This loss represents an other-than-temporary decline in the fair value of these equity securities during the year ended December 31, 2008.

Gain on Sale of HPI

We sold substantially all of the oil and gas properties of Holly Petroleum, Inc. (“HPI”), a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6 million, resulting in a gain of $6 million.

Equity in Earnings of HEP

Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP for the year ended December 31, 2008 was $3 million representing our pro-rata share of earnings in HEP from January 1 through February 29, 2008.

Income Taxes

Income taxes decreased 88% from $64 million for the year ended December 31, 2008 to $7.5 million for the year ended December 31, 2009 due to significantly lower pre-tax earnings for the year ended December 31, 2009 compared to 2008. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 17% for the year ended December 31, 2009 compared to 34.1% for 2008. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation. Our actual tax rate for income tax purposes did not decline.

Discontinued Operations

On December 1, 2009, HEP sold its 70% interest in Rio Grande resulting in a $14.5 million gain. Rio Grande operations generated net earnings of $4.4 million for the year ended December 31, 2009 compared to $2.9 million for the year ended December 31, 2008. This is presented before taking into account HEP’s noncontrolling interest in the discontinued operations.

LIQUIDITY AND CAPITAL RESOURCES

Holly Credit Agreement

We have a $400 million senior secured credit agreement expiring in March 2013 (the “Holly Credit Agreement”) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders. The Holly Credit Agreement may be used to fund working capital requirements, capital expenditures, permitted acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2010. At December 31, 2010, we had no outstanding borrowings and outstanding letters of credit totaling $71 million under the Holly Credit Agreement. At that level of usage, the unused commitment was $329 million. We entered into an amendment to the Holly Credit Agreement on May 6, 2010 that changed certain financial covenants and provided other enhancements to the agreement.

If any particular lender under the Holly Credit Agreement could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, publicly available information on our lenders is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Holly Credit Agreement. We have not experienced, nor do we expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

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HEP Credit Agreement

At December 31, 2010, HEP had a $300 million senior secured revolving credit agreement expiring in August 2011 (the “HEP Credit Agreement”) with an outstanding balance of $159 million. On February 14, 2011, the HEP Credit Agreement was amended, slightly reducing the size from $300 million to $275 million (the “HEP Amended Credit Agreement”). The HEP Amended Credit Agreement expires in February 2016; provided that the HEP Amended Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the 6.25% HEP Senior Notes have not been repurchased, refinanced, extended or repaid. The HEP Amended Credit Agreement is available to fund capital expenditures, investments, acquisitions distribution payments and working capital and for general partnership purposes.

HEP’s obligations under the HEP Amended Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our Consolidated Balance Sheets). Indebtedness under the HEP Amended Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s material, wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. During the first quarter of 2010, our previous agreements to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171 million aggregate principal amount of borrowings under the HEP Credit Agreement were terminated.

If any particular lender could not honor its commitment under the HEP Amended Credit Agreement, HEP believes the unused capacity that would be available from the remaining lenders would be sufficient to meet its borrowing needs. Additionally, publicly available information on these lenders is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the HEP Amended Credit Agreement. HEP does it expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, HEP believes there would be alternative lenders or options available.

Holly Senior Notes Due 2017

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

The Holly 9.875% 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 Holly 9.875% 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 Holly 9.875% Senior Notes.

HEP Senior Notes Due 2018 and 2015

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

HEP also has $185 million in aggregate principle amount of 6.25% senior notes maturing March 1, 2015 (the “HEP 6.25% Senior Notes”) that are registered with the SEC. The HEP 6.25% Senior Notes and HEP 8.25% 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.

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Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. During the first quarter of 2010, our previous agreement to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $35 million of the principal amount of the HEP 6.25% Senior Notes was terminated.

Holly Financing Obligation

On October 20, 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa Refinery west facility as well as certain crude oil pipeline receiving facilities to Plains for $40 million in cash. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits for crude oil purchased by them and delivered to our Tulsa Refinery west facility for storage. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing obligation. As a result, we retained these assets on our books and recorded a liability representing the $40 million in proceeds received.

HEP Equity Offerings

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

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

Liquidity

We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our credit facilities will provide sufficient resources to fund currently planned capital projects including our integration of the Tulsa Refinery facilities, and our liquidity needs for the foreseeable future. In addition, components of our growth strategy may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

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. As of December 31, 2010, we had cash and cash equivalents of $229.1 million and short-term investments in marketable securities of $1.3 million.

Cash and cash equivalents increased by $104.5 million during the year ended December 31, 2010. Net cash provided by operating activities and financing activities of $283.3 million and $34.5 million, respectively, exceeded cash used for investing activities of 213.2 million. Working capital increased by $55.7 million during 2010.

Cash Flows — Operating Activities

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

Net cash flows provided by operating activities were $283.3 million for the year ended December 31, 2010 compared to $211.5 million for the year ended December 31, 2009, an increase of $71.8 million. Net income for the year ended December 31, 2010 was $133.1 million, an increase of $79.8 million from $53.3 million for the year

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

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Net cash flows provided by operating activities were $211.5 million for the year ended December 31, 2009 compared to $155.5 million for the year ended December 31, 2008, an increase of $56 million. Net income for 2009 was $53.3 million, a decrease of $73.3 million from $126.6 million for 2008. Non-cash adjustments consisting of depreciation and amortization, interest rate swap adjustments, deferred income taxes, equity-based compensation, gain on the sale of assets and impairment of equity securities resulted in an increase to operating cash flows of $130.4 million for the year ended December 31, 2009 compared to $104.2 million for the year ended December 31, 2008. Additionally, SLC Pipeline earnings in excess of distributions decreased operating cash flows by $0.4 million in 2009 while distributions in excess of equity in earnings of HEP increased 2008 operating cash flows by $3.1 million. Changes in working capital items increased cash flows by $44 million in 2009 compared to a decrease of $37 million in 2008. For the year ended December 31, 2009, inventories increased by $17.9 million compared to a decrease of $15 million for 2008. Also for 2009, accounts receivable increased by $474.2 million compared to a decrease of $332 million for 2008 and accounts payable increased by $583.6 million compared to a decrease of $393.2 million for 2008. Additionally, for 2009, turnaround expenditures were $33.5 million compared to $34.8 million for 2008.

Cash Flows — Investing Activities and Planned Capital Expenditures

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

Net cash flows used for investing activities were $213.2 million for the year ended December 31, 2010 compared to $534.6 million for the year ended December 31, 2009, a decrease of $321.4 million. Cash expenditures for properties, plant and equipment for 2010 decreased to $213.2 million compared to $302.6 million for 2009. These include HEP capital expenditures of $25.1 million and $33 million for the years ended December 31, 2010 and 2009, respectively. Capital expenditures were significantly lower in 2010 due to a higher level of capital project initiatives in 2009 including refinery expansion projects. During the year ended December 31, 2009, we paid cash consideration of $267.1 million in connection with the Tulsa Refinery west and east facility acquisitions, invested $175.9 million in marketable securities and received proceeds of $230.3 million from the sale or maturity of marketable securities. Additionally, HEP acquired logistics and storage assets from an affiliate of Sinclair for $25.7 million and made a $25.5 million joint venture contribution to the SLC Pipeline. In December 2009, HEP sold its 70% interest in Rio Grande for $35 million. The cash proceeds received are presented net of Rio Grande’s December 1, 2009 cash balance of $3.1 million.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Net cash flows used for investing activities were $534.6 million for 2009 compared to $57.8 million for 2008, an increase of $476.8 million. Cash expenditures for properties, plant and equipment for 2009 totaled $302.6 million compared to $418.1 million for 2008. These include HEP capital expenditures of $33 million and $34.3 million for the years ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, we paid cash consideration of $267.1 million in connection with our Tulsa Refinery west and east facility acquisitions. Additionally, HEP paid cash consideration of $25.7 million upon its acquisition of logistics and storage assets from an affiliate of Sinclair and made a $25.5 million joint venture contribution to the SLC Pipeline. In December 2009, HEP sold its 70% interest in Rio Grande for $35 million. The cash proceeds received are presented net of Rio

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Grande’s December 1, 2009 cash balance of $3.1 million. Also in 2009, we invested $175.9 million in marketable securities and received proceeds of $230.3 million from sales and maturities of marketable securities. For the year ended December 31, 2008, we invested $769.1 million in marketable securities and received proceeds of $945.5 million from sales and maturities of marketable securities. Additionally in 2008, we received $6 million in proceeds from our sale of HPI and $171 million from our sale of certain crude pipelines and tankage assets to HEP. We have presented HEP’s March 1, 2008 cash balance of $7.3 million as a cash inflow as a result of our reconsolidation of HEP effective March 1, 2008.

Planned Capital Expenditures

Holly Corporation

Each year our Board of Directors approves in our annual capital budget projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or 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, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total capital budget for 2011 is $142.4 million. Additionally, capital costs of $11.7 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $185 million in capital costs in 2011, including capital projects approved in prior years. Our capital spending for 2011 is comprised of $24 million for projects at the Navajo Refinery, $13 million for projects at the Woods Cross Refinery, $70 million for projects at the Tulsa Refinery, $69 million for our portion of the UNEV Pipeline project, $3 million for asphalt plant projects and $6 million for marketing-related and miscellaneous projects. The following summarizes our key capital projects.

We are proceeding with the integration project of our Tulsa Refinery west and east facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD. The integration project involves the installation of interconnect pipelines that will permit us to transfer various intermediate streams between the two facilities. Currently, we are using an existing third-party line for the transfer of intermediates from the west facility to the east facility under a 10-year agreement. These interconnect lines will allow us to eliminate the sale of gas oil at a discount to WTI under our 5-year gas oil off take agreement with a third party, optimize gasoline blending, increase our utilization of better process technology, improve yields and reduce operating costs. HEP is currently constructing five additional interconnect pipelines and we are currently negotiating terms for a long-term agreement with HEP to transfer intermediate products via these pipelines that will commence upon completion of the project. Also, as part of the integration, we are expanding the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We are currently planning to complete the integration projects in the second quarter of 2011.

The combined Tulsa Refinery facilities also will be required to comply with new MSAT2 regulations in order to meet new federal benzene reduction requirements for gasoline. We have elected to largely use existing equipment at the Tulsa Refinery east facility to split reformate from reformers at both west and east facilities and install a new benzene saturation unit to achieve the required benzene reduction at an estimated cost of $28.5 million. We will be required to buy benzene credits to get the gasoline pool below 0.62% by volume until this project is complete, as required by law, beginning in 2011. There is an additional requirement to meet 1.3% benzene levels on an annual average beginning in July 2012. We expect to complete this project well before then.

Our consent decree with the EPA requires recovery of sulfur from the refinery fuel gas system and the shutdown or replacement of two low pressure boilers at the Tulsa Refinery west facility by the end of 2013. We have previously estimated a cost of $20 million to meet these requirements but our Board of Directors have approved a larger project for $44 million which would meet these requirements as well as increase our ability to run additional lower priced sour crude types at the Tulsa Refinery east facility. Also, we are evaluating the best solution to the low pressure boiler issue. In addition to the consent decree requirements, flare gas recovery and coker blowdown modifications are required to comply with new flare regulations at an estimated cost of $10 million.

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The Navajo Refinery currently plans to comply with the new MSAT2 regulations by the fractionation of naphtha with existing equipment to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will purchase or use credits generated at the Tulsa Refinery to reduce benzene content to the required 0.62%. Due to our acquisition of the Tulsa Refinery facilities from Sunoco and Sinclair, our Navajo Refinery has until the end of 2011 to comply with the MSAT2 regulations because we no longer qualify for the small refiner’s exemption. Also, we will be installing a new storm water surge tank and upgrade several other processes at the refinery’s Artesia waste water treatment plant. These projects are expected to cost approximately $17 million.

In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

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 2011 HEP capital budget is comprised of $5.8 million for maintenance capital expenditures and $20.1 million for expansion capital expenditures.

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Cash Flows — Financing Activities

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

Net cash flows provided by financing activities were $34.5 million for the year ended December 31, 2010 compared to $406.8 million for the year ended December 31, 2009, a decrease of $372.3 million. During 2010, we received and repaid $310 million in advances under the Holly Credit Agreement, paid $1 million under our financing obligation to Plains, purchased $1.4 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $31.9 million in dividends, received a $23.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.1 million excess tax expense on our equity based compensation. Also during this period, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $66 million and repaid $113 million under the HEP Credit Agreement, paid distributions of $48.5 million to noncontrolling interests and purchased $2.7 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs were incurred in connection with the issuance of the HEP 8.25% Senior Notes in March 2010 and an amendment to the Holly Credit Agreement. During 2009, we received $287.9 million in net proceeds upon the issuance of the Holly 9.875% Senior Notes, received and repaid $94 million in advances under the Holly Credit Agreement, received $40 million under a financing transaction with Plains, paid $30.1 million in dividends, purchased $1.2 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, received a $15.2 million contribution from our UNEV Pipeline joint venture partner and recognized $1.2 million in excess taxes on our equity based compensation. Also during this period, HEP received proceeds of $133 million upon the issuance of additional common units, received $239 million and repaid $233 million in advances under the HEP Credit Agreement and paid distributions of $33.2 million to noncontrolling interests. Additionally, we paid $8.8 million in deferred financing costs during the year ended December 31, 2009 that relate to the Holly Senior Notes issued in June 2009.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Net cash flows provided by financing activities were $406.8 million for the year ended December 31, 2009 compared to net cash flows used for financing activities of $151.3 million for the year ended December 31, 2008, an increase of $558.1 million. During 2009, we received $287.9 million in net proceeds upon the issuance of the Holly 9.875% Senior Notes, received and repaid $94 million in advances under the Holly Credit Agreement, received $40 million under a financing transaction with Plains, paid $30.1 million in dividends, purchased $1.2 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, received a $15.2 million contribution from our UNEV Pipeline joint venture partner and recognized $1.2 million in excess taxes on our equity based compensation. Also during this period, HEP received proceeds of $133 million upon the issuance of additional common units, received $239 million and repaid $233 million in advances under the HEP Credit Agreement and paid distributions of $33.2 million to noncontrolling interest holders. Additionally, we paid $8.8 million in deferred financing costs during the year ended December 31, 2009 that relate to the Holly Senior Notes issued in June 2009. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29 million under the HEP Credit Agreement and purchased $0.8 million in HEP common units in the open market for restricted unit grants. Additionally in 2008, we paid an aggregate of $0.9 million in deferred financing costs related to the amendment and restatement of the Holly Credit Agreement and the HEP Credit Agreement. Under our common stock repurchase program, we purchased treasury stock of $151.1 million in 2008. We also paid $29.1 million in dividends, received a $17 million contribution from our UNEV Pipeline joint venture partner, received $1 million for common stock issued upon exercise of stock options and recognized $5.7 million in excess tax benefits on our equity based compensation during 2008. Also during this period, HEP paid $22.1 million in distributions to its noncontrolling interest holders.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2010 in total and by period due beginning in 2011. 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,

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“Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.


			Payments Due by Period
			Less than						Over
Contractual Obligations and Commitments	Total		1 Year		1-3 Years		3-5 Years		5 Years
	(In thousands)
Holly Corporation⁽¹⁾⁽²⁾
Long-term debt — principal⁽³⁾	$	338,781	$	1,160	$	2,786	$	3,547	$	331,288
Long-term debt — interest⁽⁴⁾		233,001		34,265		68,064		67,304		63,368
Transportation agreements⁽⁵⁾		344,921		35,191		70,380		70,380		168,970
Hydrogen supply agreement⁽⁶⁾		81,851		6,548		13,096		13,096		49,111
Operating leases		41,504		9,831		13,177		8,638		9,858

		1,040,058		86,995		167,503		162,965		622,595

Holly Energy Partners
Long-term debt — principal⁽⁷⁾		494,000		—		—		185,000		309,000
Long-term debt — interest⁽⁸⁾		161,228		27,134		54,269		48,488		31,337
Pipeline operating and right of way leases		42,424		6,545		12,954		12,839		10,086
Other agreements		9,814		1,135		2,120		2,120		4,439

		707,466		34,814		69,343		248,447		354,862

Total	$	1,747,524	$	121,809	$	236,846	$	411,412	$	977,457


(1)		We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits of $2 million as of December 31, 2010 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 14 to the Consolidated Financial Statements.

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

(3)		Our long-term debt consists of the $300 million principal balance on the Holly 9.875% Senior Notes and a long-term financing obligation having a principal balance of $38.8 million at December 31, 2010.

(4)		Interest payments consist of interest on the 9.875% Holly Senior Notes and on our long-term financing obligation.

(5)		Consists of contractual obligations under agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries under contracts expiring between 2016 and 2024.

(6)		We have entered into a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices through 2023. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term. We have estimated the future payments in the table above using current market rates. Therefore, actual amounts expended for this obligation in the future could vary significantly from the amounts presented above.

(7)		HEP’s long-term debt consists of the $150 million and the $185 million principal balances on the 8.25% and 6.25% HEP Senior Notes and $159 million of outstanding principal under the HEP Credit Agreement. The HEP Credit Agreement was amended on February 14, 2011. The HEP Amended Credit Agreement expires in 2016.

(8)		Interest payments consist of interest on the 6.25% and 8.25% HEP Senior Notes and interest on long-term debt under the HEP Credit Agreement. Interest under the credit agreement debt is based on an effective interest rate of 5.49% at December 31, 2010.

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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 GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows. For additional information, see Note 1 to the Consolidated Financial Statements “Description of Business and Summary of Significant Accounting Policies.”

Inventory Valuation

Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market 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, 2010, 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, 2010, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $284 million. An actual valuation of inventory under the LIFO method can be made only 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 utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit.

Long-lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2010, 2009 and 2008.

Variable Interest Entity

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

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We reconsolidated HEP effective March 1, 2008, following its acquisition of our crude pipeline and tankage assets (see Note 3 to the Consolidated Financial Statements). Prior to March 1, 2008, we accounted for our investment in HEP using the equity method of accounting whereby we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance.

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 to mitigate price exposure with respect to:

	•		our inventory positions;

	•		natural gas purchases;

	•		costs of crude oil; and

	•		prices of refined products.

As of December 31, 2010, we have outstanding commodity price swap contracts serving as economic hedges to protect the value of a temporary crude oil inventory build of 120,000 barrels against price volatility. These contracts are measured quarterly at fair value with offsetting adjustments (gains / losses) recorded directly to cost of products sold.

We also have outstanding price swap contracts that fix our purchase price on forecasted natural gas purchases aggregating of 1,500,000 MMBTUs to be ratably purchased between January and March 2011 at a weighted-average cost of $4.20 per MMBTU. These price swap contracts have been designated as cash flow hedges and mature in March 2011.

Under hedge accounting, a cash flow hedge is adjusted quarterly to fair value with offsetting fair value adjustments to other comprehensive income. These fair value adjustments (gains / losses) are later reclassified into earnings as the hedging instrument matures. Also on a quarterly basis, hedge effectiveness is measured by comparing the change in fair value of the swap contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any ineffectiveness is reclassified from accumulated other comprehensive income into earnings.

Interest Rate Risk Management

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

As of December 31, 2010, HEP has an interest rate swap contract that hedges its exposure to the cash flow risk caused by the effects of changes in the London Interbank Offered Rate (“LIBOR”) on a $155 million HEP Credit

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Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin of 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2010. This interest rate swap contract has been designated as a cash flow hedge and matures in February 2013.

This contract initially hedged variable LIBOR interest on $171 million in outstanding HEP Credit Agreement debt. In May 2010, HEP repaid $16 million of the HEP Credit Agreement debt and also settled a corresponding portion of its interest rate swap agreement having a notional amount of $16 million for $1.1 million. Upon payment, HEP reduced its swap liability and reclassified a $1.1 million charge from accumulated other comprehensive loss to interest expense, representing the application of hedge accounting prior to settlement.

The following table presents balance sheet locations and related fair values of outstanding derivative instruments.


	Balance Sheet			Location of	Offsetting
Derivative Instruments	Location	Fair Value		Offsetting Balance	Amount
	(Dollars in thousands)
December 31, 2010
*Derivatives designated as cash flow hedging instruments:*
Variable-to-fixed commodity price swap contracts (forecasted volumes of natural gas purchases)	Accrued liabilities	$	38	Accumulated other comprehensive loss	$	38

Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss	$	10,026

*Derivatives not designated as hedging instruments:*
Fixed-to-variable rate swap contracts (various inventory positions)	Accrued liabilities	$	497	Cost of products sold	$	497

December 31, 2009
*Derivative designated as cash flow hedging instrument:*
Variable-to-fixed interest rate swap contract ($171 million LIBOR based debt interest payments)	Other long-term liabilities	$	9,141	Accumulated other comprehensive loss	$	9,141

*Derivatives not designated as hedging instruments:*
Fixed-to-variable interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other assets	$	2,294	Long-term debt	$	1,791	⁽¹⁾
				Equity		503	⁽²⁾

		$	2,294		$	2,294

Variable-to-fixed interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other long-term liabilities	$	2,555	Equity	$	2,555	⁽²⁾


(1)		Represents unamortized balance of a deferred hedge premium attributable to HEP’s fair value hedge that was dedesignated in 2008 that is being amortized as a reduction to interest expense over the remaining term of the HEP 6.25% Senior Notes.

(2)		Represents prior year charges to interest expense.

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

For the years ended December 31, 2010, 2009 and 2008, HEP recognized $1.5 million, $0.2 million and $2.3 million, respectively, in charges to interest expense as a result of fair value changes to its interest rate swap contracts.

There was no ineffectiveness on the cash flow hedges during the periods covered in these consolidated financial statements.

Publicly available information is reviewed on the counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the swap contracts. These counterparties

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consist of large financial institutions. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their commitments.

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

At December 31, 2010, outstanding principal under the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes was $300 million, $185 million and $150 million, respectively. For these fixed rate notes, changes in interest rates will generally affect fair value of the debt, but not our earnings or cash flows. At December 31, 2010, the estimated fair values of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $327 million, $183.2 million and $156.8 million, respectively. We estimate that a hypothetical 10% change in the yield-to-maturity rates applicable to these notes would result in a fair value change to the notes of approximately $13 million, $4.3 million and $6.3 million, respectively.

For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2010, borrowings outstanding under the HEP Credit Agreement were $159 million. By means of its cash flow hedge, HEP has effectively converted the variable rate on $155 million of outstanding principal to a fixed rate of 5.49%. For the unhedged $4 million portion, a hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.

At December 31, 2010, cash and cash equivalents included investments in investment grade, highly liquid investments with maturities of three months or less at the time of purchase and hence the interest rate market risk implicit in these cash investments is low. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

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

Set forth below is our calculation of EBITDA from continuing operations.


	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Income from continuing operations	$	133,051		$	36,343		$	123,718
Subtract noncontrolling interest in income from continuing operations		(29,087	)		(21,134	)		(4,512	)
Add income tax provision		59,312			7,460			64,028
Add interest expense		74,196			40,346			23,955
Subtract interest income		(1,168	)		(5,045	)		(10,797	)
Add depreciation and amortization		117,529			98,751			62,995

EBITDA from continuing operations	$	353,833		$	156,721		$	259,387

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

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

We calculate refinery gross margin and net operating margin using net sales, cost of products and operating expenses, in each case averaged per produced barrel sold. These two margins do not include the effect of depreciation and amortization. Each of these component performance measures can be reconciled directly to our Consolidated Statements of Income.

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

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Refinery Gross Margin

Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Refinery gross margin for each of our refineries and for our three refineries on a consolidated basis is calculated as shown below.


	Years Ended December 31,
	2010		2009		2008
Average per produced barrel:

*Navajo Refinery*
Net sales	$	90.37	$	73.15	$	108.52
Less cost of products		83.12		65.95		98.97

Refinery gross margin	$	7.25	$	7.20	$	9.55


*Woods Cross Refinery*
Net sales	$	94.26	$	70.25	$	110.07
Less cost of products		75.54		58.98		93.47

Refinery gross margin	$	18.72	$	11.27	$	16.60


*Tulsa Refinery*
Net sales	$	90.84	$	78.89	$	—
Less cost of products		83.29		74.56		—

Refinery gross margin	$	7.55	$	4.33	$	—


*Consolidated*
Net sales	$	91.06	$	74.06	$	108.83
Less cost of products		82.27		66.85		97.87

Refinery gross margin	$	8.79	$	7.21	$	10.96

Net Operating Margin

Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. Net operating margin for each of our refineries and for our three refineries on a consolidated basis is calculated as shown below.


	Years Ended December 31,
	2010		2009			2008
Average per produced barrel:

*Navajo Refinery*
Refinery gross margin	$	7.25	$	7.20		$	9.55
Less refinery operating expenses		4.95		4.81			4.58

Net operating margin	$	2.30	$	2.39		$	4.97


*Woods Cross Refinery*
Refinery gross margin	$	18.72	$	11.27		$	16.60
Less refinery operating expenses		6.09		6.60			7.42

Net operating margin	$	12.63	$	4.67		$	9.18


*Tulsa Refinery*
Refinery gross margin	$	7.55	$	4.33		$	—
Less refinery operating expenses		4.94		5.25			—

Net operating margin	$	2.61	$	(0.92	)	$	—


*Consolidated*
Refinery gross margin	$	8.79	$	7.21		$	10.96
Less refinery operating expenses		5.08		5.24			5.14

Net operating margin	$	3.71	$	1.97		$	5.82

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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,
	2010			2009			2008
	(Dollars in thousands, except per barrel amounts)
*Navajo Refinery*
Average sales price per produced barrel sold	$	90.37		$	73.15		$	108.52
Times sales of produced refined products sold (BPD)		92,550			87,140			89,580
Times number of days in period		365			365			366

Refined product sales from produced products sold	$	3,052,766		$	2,326,616		$	3,557,967


*Woods Cross Refinery*
Average sales price per produced barrel sold	$	94.26		$	70.25		$	110.07
Times sales of produced refined products sold (BPD)		27,810			26,870			22,370
Times number of days in period		365			365			366

Refined product sales from produced products sold	$	956,800		$	688,980		$	901,189


*Tulsa Refinery*
Average sales price per produced barrel sold	$	90.84		$	78.89		$	—
Times sales of produced refined products sold (BPD)		107,780			37,570			—
Times number of days in period		365			365			—

Refined product sales from produced products sold	$	3,573,618		$	1,081,823		$	—


Sum of refined product sales from produced products sold from our three refineries ⁽¹⁾	$	7,583,184		$	4,097,419		$	4,459,156
Add refined product sales from purchased products and rounding ⁽²⁾		130,348			106,969			384,073

Total refined products sales		7,713,532			4,204,388			4,843,229
Add direct sales of excess crude oil ⁽³⁾		459,743			453,958			860,642
Add other refining segment revenue ⁽⁴⁾		113,725			131,475			133,578

Total refining segment revenue		8,287,000			4,789,821			5,837,449
Add HEP segment sales and other revenues		182,114			146,561			94,439
Add corporate and other revenues		415			(636	)		2,641
Subtract consolidations and eliminations		(146,600	)		(101,478	)		(74,172	)

Sales and other revenues	$	8,322,929		$	4,834,268		$	5,860,357


(1)		The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.

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

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

(4)		Other refining segment revenue includes revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales.


	Years Ended December 31,
	2010		2009		2008
	(Dollars in thousands, except per barrel amounts)
Average sales price per produced barrel sold	$	91.06	$	74.06	$	108.83
Times sales of produced refined products sold (BPD)		228,140		151,580		111,950
Times number of days in period		365		365		366

Refined product sales from produced products sold	$	7,583,184	$	4,097,419	$	4,459,156

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


	Years Ended December 31,
	2010			2009			2008
	(Dollars in thousands, except per barrel amounts)
*Navajo Refinery*
Average cost of products per produced barrel sold	$	83.12		$	65.95		$	98.97
Times sales of produced refined products sold (BPD)		92,550			87,140			89,580
Times number of days in period		365			365			366

Cost of products for produced products sold	$	2,807,856		$	2,097,612		$	3,244,858


*Woods Cross Refinery*
Average cost of products per produced barrel sold	$	75.54		$	58.98		$	93.47
Times sales of produced refined products sold (BPD)		27,810			26,870			22,370
Times number of days in period		365			365			366

Cost of products for produced products sold	$	766,780		$	578,449		$	765,278


*Tulsa Refinery*
Average cost of products per produced barrel sold	$	83.29		$	74.56		$	—
Times sales of produced refined products sold (BPD)		107,780			37,570			—
Times number of days in period		365			365			—

Cost of products for produced products sold	$	3,276,604		$	1,022,445		$	—


Sum of cost of products for produced products sold from our three refineries ⁽¹⁾	$	6,851,240		$	3,698,506		$	4,010,136
Add refined product costs from purchased products sold and rounding ⁽²⁾		131,141			114,650			389,944

Total refined cost of products sold		6,982,381			3,813,156			4,400,080
Add crude oil cost of direct sales of excess crude oil ⁽³⁾		454,566			449,488			853,360
Add other refining segment cost of products sold ⁽⁴⁾		73,410			75,229			101,144

Total refining segment cost of products sold		7,510,357			4,337,873			5,354,584
Subtract consolidations and eliminations		(143,208	)		(99,865	)		(73,885	)

Cost of products sold (exclusive of depreciation and amortization)	$	7,367,149		$	4,238,008		$	5,280,699


(1)		The above calculations of cost of products for produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.

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

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

(4)		Other refining segment cost of products sold includes the cost of products for Holly Asphalt and costs attributable to feedstock and sulfur credit sales.


	Years Ended December 31,
	2010		2009		2008
	(Dollars in thousands, except per barrel amounts)
Average cost of products per produced barrel sold	$	82.27	$	66.85	$	97.87
Times sales of produced refined products sold (BPD)		228,140		151,580		111,950
Times number of days in period		365		365		366

Cost of products for produced products sold	$	6,851,240	$	3,698,506	$	4,010,136

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


	Years Ended December 31,
	2010			2009			2008
	(Dollars in thousands, except per barrel amounts)
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	4.95		$	4.81		$	4.58
Times sales of produced refined products sold (BPD)		92,550			87,140			89,580
Times number of days in period		365			365			366

Refinery operating expenses for produced products sold	$	167,215		$	152,987		$	150,161


*Woods Cross Refinery*
Average refinery operating expenses per produced barrel sold	$	6.09		$	6.60		$	7.42
Times sales of produced refined products sold (BPD)		27,810			26,870			22,370
Times number of days in period		365			365			366

Refinery operating expenses for produced products sold	$	61,817		$	64,730		$	60,751


*Tulsa Refinery*
Average refinery operating expenses per produced barrel sold	$	4.94		$	5.25		$	—
Times sales of produced refined products sold (BPD)		107,780			37,570			—
Times number of days in period		365			365			—

Refinery operating expenses for produced products sold	$	194,338		$	71,994		$	—


Sum of refinery operating expenses per produced products sold from our three refineries ⁽¹⁾	$	423,370		$	289,711		$	210,912
Add other refining segment operating expenses and rounding ⁽²⁾		26,220			23,609			21,599

Total refining segment operating expenses		449,590			313,320			232,511
Add HEP segment operating expenses		52,947			44,003			33,353
Add corporate and other costs		2,387			41			128
Subtract consolidations and eliminations		(510	)		(509	)		(287	)

Operating expenses (exclusive of depreciation and amortization)	$	504,414		$	356,855		$	265,705


(1)		The above calculations of refinery operating expenses per produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.

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


	Years Ended December 31,
	2010		2009		2008
	(Dollars in thousands, except per barrel amounts)
Average refinery operating expenses per produced barrel sold	$	5.08	$	5.24	$	5.14
Times sales of produced refined products sold (BPD)		228,140		151,580		111,950
Times number of days in period		365		365		366

Refinery operating expenses for produced products sold	$	423,370	$	289,711	$	210,912

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


	Years Ended December 31,
	2010		2009		2008
	(Dollars in thousands, except per barrel amounts)
*Navajo Refinery*
Net operating margin per barrel	$	2.30	$	2.39	$	4.97
Add average refinery operating expenses per produced barrel		4.95		4.81		4.58

Refinery gross margin per barrel		7.25		7.20		9.55
Add average cost of products per produced barrel sold		83.12		65.95		98.97

Average sales price per produced barrel sold	$	90.37	$	73.15	$	108.52
Times sales of produced refined products sold (BPD)		92,550		87,140		89,580
Times number of days in period		365		365		366

Refined product sales from produced products sold	$	3,052,766	$	2,326,616	$	3,557,967

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	Years Ended December 31,
	2010			2009			2008
	(Dollars in thousands, except per barrel amounts)
*Woods Cross Refinery*
Net operating margin per barrel	$	12.63		$	4.67		$	9.18
Add average refinery operating expenses per produced barrel		6.09			6.60			7.42

Refinery gross margin per barrel		18.72			11.27			16.60
Add average cost of products per produced barrel sold		75.54			58.98			93.47

Average sales price per produced barrel sold	$	94.26		$	70.25		$	110.07
Times sales of produced refined products sold (BPD)		27,810			26,870			22,370
Times number of days in period		365			365			366

Refined product sales from produced products sold	$	956,800		$	688,980		$	901,189


*Tulsa Refinery*
Net operating margin per barrel	$	2.61		$	(0.92	)	$	—
Add average refinery operating expenses per produced barrel		4.94			5.25			—

Refinery gross margin per barrel		7.55			4.33			—
Add average cost of products per produced barrel sold		83.29			74.56			—

Average sales price per produced barrel sold	$	90.84		$	78.89		$	—
Times sales of produced refined products sold (BPD)		107,780			37,570			—
Times number of days in period		365			365			—

Refined product sales from produced products sold	$	3,573,618		$	1,081,823		$	—


Sum of refined product sales from produced products sold from our three refineries ⁽¹⁾	$	7,583,184		$	4,097,419		$	4,459,156
Add refined product sales from purchased products and rounding ⁽²⁾		130,348			106,969			384,073

Total refined product sales		7,713,532			4,204,388			4,843,229
Add direct sales of excess crude oil ⁽³⁾		459,743			453,958			860,642
Add other refining segment revenue ⁽⁴⁾		113,725			131,475			133,578

Total refining segment revenue		8,287,000			4,789,821			5,837,449
Add HEP segment sales and other revenues		182,114			146,561			94,439
Add corporate and other revenues		415			(636	)		2,641
Subtract consolidations and eliminations		(146,600	)		(101,478	)		(74,172	)

Sales and other revenues	$	8,322,929		$	4,834,268		$	5,860,357


(1)		The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.

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

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

(4)		Other refining segment revenue includes the revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales.


	Years Ended December 31,
	2010		2009		2008
	(Dollars in thousands, except per barrel amounts)
Net operating margin per barrel	$	3.71	$	1.97	$	5.82
Add average refinery operating expenses per produced barrel		5.08		5.24		5.14

Refinery gross margin per barrel		8.79		7.21		10.96
Add average cost of products per produced barrel sold		82.27		66.85		97.87

Average sales price per produced barrel sold	$	91.06	$	74.06	$	108.83
Times sales of produced refined products sold (BPD)		228,140		151,580		111,950
Times number of days in period		365		365		366

Refined product sales from produced products sold	$	7,583,184	$	4,097,419	$	4,459,156

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Item 8. Financial Statements and Supplementary Data

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

Management of Holly 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, 2010 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, 2010, 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, 2010. That report appears on page 72.

-71-

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
and Stockholders of Holly Corporation

We have audited Holly Corporation’s (the “Company”) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Holly 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. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, Holly Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, 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 Holly Corporation as of December 31, 2010 and 2009, and the related consolidated statements of income, cash flows, equity and comprehensive income for each of the three years in the period ended December 31, 2010 and our report dated February 25, 2011 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 25, 2011

-72-

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
and Stockholders of Holly Corporation

We have audited the accompanying consolidated balance sheets of Holly Corporation as of December 31, 2010 and 2009, and the related consolidated statements of income, cash flows, equity and comprehensive income for each of the three years in the period ended December 31, 2010. 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 Holly Corporation at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Corporation’s internal control over financial reporting as of December 31, 2010, 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 25, 2011 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 25, 2011

-74-

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)


	December 31,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents (HEP: $403 and $2,508, respectively)	$	229,101		$	124,596
Marketable securities		1,343			1,223

Accounts receivable, net: Product and transportation (HEP: $22,508 and $18,767, respectively)		299,081			292,310
Crude oil resales		694,035			470,145

		993,116			762,455

Inventories: Crude oil and refined products		353,636			259,582
Materials and supplies (HEP: $202 and $165, respectively)		46,731			43,931

		400,367			303,513

Income taxes receivable		51,034			38,072
Prepayments and other (HEP: $573 and $574, respectively)		28,474			50,957
Current assets of discontinued operations (HEP: $2,195)		—			2,195

Total current assets		1,703,435			1,283,011

Properties, plants and equipment, at cost (HEP: $552,398 and $491,999, respectively)		2,215,828			2,001,855
Less accumulated depreciation (HEP: $(60,300) and $(33,478), respectively)		(459,137	)		(371,885	)

		1,756,691			1,629,970

Other assets: Turnaround costs		69,533			53,463
Goodwill (HEP: $81,602 and $81,602)		81,602			81,602
Intangibles and other (HEP: $72,434 and $77,443, respectively)		90,214			97,893

		241,349			232,958

Total assets	$	3,701,475		$	3,145,939


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $10,238 and $6,211, respectively)	$	1,317,446		$	975,155
Accrued liabilities (HEP: $21,206 and $13,594, respectively)		72,409			49,957

Total current liabilities		1,389,855			1,025,112

Long-term debt (HEP: $482,271 and $379,198, respectively)		810,561			707,458
Deferred income taxes		131,935			124,585
Other long-term liabilities (HEP: $10,809 and $12,349, respectively)		80,985			81,003

Equity:
Holly Corporation stockholders’ equity:
Preferred stock, $1.00 par value — 1,000,000 shares authorized; none issued		—			—
Common stock $.01 par value — 160,000,000 shares authorized; 76,346,432 and 76,359,006 shares issued as of December 31, 2010 and December 31, 2009, respectively		763			764
Additional capital		194,378			195,565
Retained earnings		1,206,328			1,134,341
Accumulated other comprehensive loss		(26,246	)		(25,700	)
Common stock held in treasury, at cost — 23,081,744 and 23,292,737 shares as of December 31, 2010 and 2009, respectively		(677,804	)		(685,931	)

Total Holly Corporation stockholders’ equity		697,419			619,039

Noncontrolling interest		590,720			588,742

Total equity		1,288,139			1,207,781

Total liabilities and equity	$	3,701,475		$	3,145,939

Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2010 and December 31, 2009. HEP is a consolidated variable interest entity.

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)


	Years Ended December 31,
	2010			2009			2008
Sales and other revenues	$	8,322,929		$	4,834,268		$	5,860,357

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		7,367,149			4,238,008			5,280,699
Operating expenses (exclusive of depreciation and amortization)		504,414			356,855			265,705
General and administrative expenses (exclusive of depreciation and amortization)		70,839			60,343			55,278
Depreciation and amortization		117,529			98,751			62,995

Total operating costs and expenses		8,059,931			4,753,957			5,664,677


Income from operations		262,998			80,311			195,680

Other income (expense):
Equity in earnings of SLC Pipeline		2,393			1,919			—
Interest income		1,168			5,045			10,797
Interest expense		(74,196	)		(40,346	)		(23,955	)
Acquisition costs — Tulsa refineries		—			(3,126	)		—
Impairment of equity securities		—			—			(3,724	)
Gain on sale of Holly Petroleum, Inc.		—			—			5,958
Equity in earnings of Holly Energy Partners		—			—			2,990

		(70,635	)		(36,508	)		(7,934	)

Income from continuing operations before income taxes		192,363			43,803			187,746

Income tax provision:
Current		35,472			(30,062	)		31,094
Deferred		23,840			37,522			32,934

		59,312			7,460			64,028

Income from continuing operations		133,051			36,343			123,718

Discontinued operations
Income from discontinued operations, net of taxes		—			4,425			2,918
Gain on sale of discontinued operations, net of taxes		—			12,501			—

Income from discontinued operations		—			16,926			2,918


Net income		133,051			53,269			126,636

Less net income attributable to noncontrolling interest		29,087			33,736			6,078


Net income attributable to Holly Corporation stockholders	$	103,964		$	19,533		$	120,558


Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	103,964		$	15,209		$	119,206
Income from discontinued operations		—			4,324			1,352

Net income	$	103,964		$	19,533		$	120,558


Earnings per share attributable to Holly Corporation stockholders — basic:
Income from continuing operations	$	1.95		$	0.30		$	2.37
Income from discontinued operations		—			0.09			0.03

Net income	$	1.95		$	0.39		$	2.40


Earnings per share attributable to Holly Corporation stockholders — diluted:
Income from continuing operations	$	1.94		$	0.30		$	2.36
Income from discontinued operations		—			0.09			0.02

Net income	$	1.94		$	0.39		$	2.38


Average number of common shares outstanding:
Basic		53,218			50,418			50,202
Diluted		53,609			50,603			50,549

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


	Years Ended December 31,
	2010			2009			2008
Cash flows from operating activities:
Net income	$	133,051		$	53,269		$	126,636
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes discontinued operations)		117,529			99,633			63,789
SLC Pipeline distributions in excess of earnings (earnings in excess of distributions)		482			(419	)		—
Deferred income taxes		23,840			37,522			32,934
Distributions in excess of equity in earnings of Holly Energy Partners		—			—			3,067
Equity based compensation expense		11,498			7,549			7,467
Gain on sale of assets, before income taxes		—			(14,479	)		(5,958	)
Change in fair value — interest rate swaps		1,464			175			2,282
Impairment of equity securities		—			—			3,724
(Increase) decrease in current assets:
Accounts receivable		(228,466	)		(474,205	)		331,978
Inventories		(96,854	)		(17,904	)		15,006
Income taxes receivable		(14,990	)		(33,270	)		10,006
Prepayments and other		369			(15,816	)		(398	)
Increase (decrease) in current liabilities:
Accounts payable		342,182			583,550			(393,186	)
Accrued liabilities		22,414			1,651			(2,149	)
Income taxes payable		—			—			1,781
Turnaround expenditures		(34,966	)		(33,541	)		(34,751	)
Other, net		5,702			17,830			(6,738	)

Net cash provided by operating activities		283,255			211,545			155,490

Cash flows from investing activities:
Additions to properties, plants and equipment — Holly Corporation		(188,129	)		(269,552	)		(383,742	)
Additions to properties, plants and equipment — Holly Energy Partners		(25,103	)		(32,999	)		(34,317	)
Acquisition of Tulsa Refinery facilities — Holly Corporation		—			(267,141	)		—
Acquisition of logistics assets from Sinclair Oil Company — Holly Energy Partners		—			(25,665	)		—
Investment in SLC Pipeline — Holly Energy Partners		—			(25,500	)		—
Proceeds from sale of interest in Rio Grande Pipeline Company, net of transferred cash — Holly Energy Partners		—			31,865			—
Proceeds from sale of crude pipelines and tankage assets		—			—			171,000
Proceeds from sale of Holly Petroleum, Inc.		—			—			5,958
Increase in cash due to consolidation of Holly Energy Partners		—			—			7,295
Purchases of marketable securities		—			(175,892	)		(769,142	)
Sales and maturities of marketable securities		—			230,281			945,461
Investment in Holly Energy Partners		—			—			(290	)

Net cash used for investing activities		(213,232	)		(534,603	)		(57,777	)

Cash flows from financing activities:
Borrowings under credit agreement — Holly Corporation		310,000			94,000			—
Repayments under credit agreement — Holly Corporation		(310,000	)		(94,000	)		—
Borrowings under credit agreement — Holly Energy Partners		66,000			239,000			114,000
Repayments under credit agreement — Holly Energy Partners		(113,000	)		(233,000	)		(85,000	)
Repayments under financing agreement — Holly Corporation		(1,028	)		—			—
Proceeds from issuance of senior notes — Holly Corporation		—			287,925			—
Proceeds from issuance of senior notes — Holly Energy Partners		147,540			—			—
Proceeds from issuance of common units — Holly Energy Partners		—			133,035			—
Proceeds from Plains financing transaction		—			40,000			—
Deferred financing costs		(3,121	)		(8,842	)		(913	)
Purchase of treasury stock		(1,368	)		(1,214	)		(151,106	)
Contribution from joint venture partner		23,500			15,150			17,000
Dividends		(31,868	)		(30,123	)		(29,064	)
Distributions to noncontrolling interest		(48,493	)		(33,200	)		(22,098	)
Issuance of common stock upon exercise of options		118			134			1,005
Purchase of units for restricted grants		(2,704	)		(616	)		(795	)
Excess tax (expense) benefit from equity based compensation		(1,094	)		(1,209	)		5,694
Other		—			(191	)		—

Net cash provided by (used for) financing activities		34,482			406,849			(151,277	)

Cash and cash equivalents:

Increase (decrease) for the period		104,505			83,791			(53,564	)
Beginning of period		124,596			40,805			94,369

End of period	$	229,101		$	124,596		$	40,805


Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	66,674		$	39,995		$	14,346
Income taxes	$	62,084		$	19,344		$	21,084

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)


	Holly Corporation Stockholders’ Equity
										Accumulated Other						Non-
	Common			Additional			Retained			Comprehensive			Treasury			controlling
	Stock			Capital			Earnings			Income (Loss)			Stock			Interest			Total Equity
Balance at December 31, 2007	$	733		$	109,125		$	1,054,974		$	(19,076	)	$	(551,962	)	$	8,333		$	602,127
Reconsolidation of Holly Energy Partners (March 1, 2008)		—			—			—			—			—			389,184			389,184
Net income		—			—			120,558			—			—			6,078			126,636
Dividends		—			—			(30,144	)		—			—			—			(30,144	)
Distributions to noncontrolling interest holders		—			—			—			—			—			(22,098	)		(22,098	)
Other comprehensive loss		—			—			—			(16,005	)		—			(7,079	)		(23,084	)
Contribution from joint venture partner		—			—			—			—			—			18,500			18,500
Issuance of common stock upon exercise of stock options		2			1,003			—			—			—			—			1,005
Tax benefit from stock options		—			3,364			—			—			—			—			3,364
Issuance of restricted stock, net of forfeitures		—			5,476			—			—			—			—			5,476
Other equity based compensation		—			2,330			—			—			—			1,732			4,062
Purchase of units for restricted grants		—			—			—			—			—			(795	)		(795	)
Purchase of treasury stock		—			—			—			—			(138,838	)		—			(138,838	)
Other		—			—			—			—			—			937			937


Balance at December 31, 2008	$	735		$	121,298		$	1,145,388		$	(35,081	)	$	(690,800	)	$	394,792		$	936,332
Net income		—			—			19,533			—			—			33,736			53,269
Dividends		—			—			(30,580	)		—			—			—			(30,580	)
Distributions to noncontrolling interest holders		—			—			—			—			—			(33,200	)		(33,200	)
Elimination of noncontrolling interest upon HEP’s sale of Rio Grande Pipeline Company		—			—			—			—			—			(8,718	)		(8,718	)
Other comprehensive income		—			—			—			9,381			—			2,021			11,402
Issuance of common shares		28			73,972			—			—			—			—			74,000
Issuance of HEP common units, net of issuing costs		—			—			—			—			—			186,801			186,801
Contribution from joint venture partner		—			—			—			—			—			13,650			13,650
Issuance of common stock upon exercise of stock options		1			134			—			—			—			—			135
Tax benefit from stock options		—			371			—			—			—			—			371
Issuance of restricted stock, net of forfeitures		—			5,270			—			—			—			—			5,270
Other equity based compensation		—			(5,480	)		—			—			6,083			699			1,302
Purchase of treasury stock		—			—			—			—			(1,214	)		—			(1,214	)
Other		—			—			—			—			—			(1,039	)		(1,039	)


Balance at December 31, 2009	$	764		$	195,565		$	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		—			—			—			(546	)		—			(1,623	)		(2,169	)
Contribution from joint venture partner		—			—			—			—			—			23,500			23,500
Issuance of common stock upon exercise of stock options		—			118			—			—			—			—			118
Tax benefit from stock options		—			416			—			—			—			—			416
Issuance of restricted stock, net of forfeitures		—			7,773			—			—			—			—			7,773
Other equity based compensation		(1	)		(9,494	)		—			—			9,495			2,215			2,215
Purchase of treasury stock		—			—			—			—			(1,368	)		—			(1,368	)
Other		—			—			—			—			—			(2,708	)		(2,708	)


Balance at December 31, 2010	$	763		$	194,378		$	1,206,328		$	(26,246	)	$	(677,804	)	$	590,720		$	1,288,139

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)


	Years Ended December 31,
	2010			2009		2008
Net income	$	133,051		$	53,269	$	126,636

Other comprehensive income (loss):

Securities available-for-sale:
Unrealized gain (loss) on available-for-sale securities		114			173		1,146
Reclassification adjustment to net income on sale of marketable securities		—			236		(1,315	)

Total unrealized gain (loss) on available-for-sale securities		114			409		(169	)


Hedging instruments:
Change in fair value of cash flow hedging instruments		(1,999	)		3,726		(12,967	)
Reclassification adjustment to net income on maturity/settlement of cash flow hedging instruments		1,076			—		—

Total unrealized gain (loss) on hedging instruments		(923	)		3,726		(12,967	)

Retirement medical obligation adjustment		(238	)		742		1,433
Minimum pension liability adjustment		(1,470	)		12,497		(21,572	)


Other comprehensive income (loss) before income taxes		(2,517	)		17,374		(33,275	)

Income tax expense (benefit)		(348	)		5,972		(10,191	)


Other comprehensive income (loss)		(2,169	)		11,402		(23,084	)


Total comprehensive income		130,882			64,671		103,552

Less noncontrolling interest in comprehensive income (loss)		27,464			35,757		(1,001	)


Comprehensive income attributable to Holly Corporation stockholders	$	103,418		$	28,914	$	104,553

See accompanying notes.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Description of Business: References herein to Holly Corporation include Holly Corporation 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 Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions or obligations between HEP and Holly Corporation 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 Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

We are principally an independent petroleum refiner that produces high value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns 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 (collectively, the “Navajo Refinery”). The Navajo Refinery can process sour (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. Our refinery located just north of Salt Lake City, Utah (the “Woods Cross Refinery”) is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes regional sweet (lower sulfur) and sour Canadian crude oils. Our refinery located in Tulsa, Oklahoma (the “Tulsa Refinery”) is comprised of two facilities, the Tulsa Refinery west and east facilities. See Note 2 for additional information on the Tulsa Refinery facilities acquired in 2009.

At December 31, 2010, we owned a 34% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner interest. HEP has logistic assets including petroleum product and crude oil pipelines located in Texas, New Mexico, Oklahoma and Utah; ten refined product terminals; a jet fuel terminal; loading rack facilities at each of our three refineries, a refined products tank farm facility and on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries. Additionally, HEP owns a 25% interest in SLC Pipeline LLC (“SLC Pipeline”), a new 95-mile intrastate pipeline system that serves refiners 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 a 50% or more ownership interest or through a controlling financial interest with respect to variable interest entities. All significant intercompany transactions and balances have been eliminated.

Use of Estimates: The preparation of financial statements in accordance with U.S. generally accepted accounting principles (“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 conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings.

Marketable Securities: We consider all marketable debt securities with maturities greater than three months at the date of purchase to be marketable securities. Our marketable securities are primarily issued by government entities with the maximum maturity of any individual issue not more than two years, while the maximum duration of the

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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 the 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 $2.1 million and $2.5 million at December 31, 2010 and 2009, 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 and refined products and the average cost method for materials and supplies, 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 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 can be made only 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.

Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. No impairments of long-lived assets were recorded during the years ended December 31, 2010, 2009 and 2008.

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.

We have asset retirement obligations with respect to certain assets due to legal obligations to clean and/or dispose of various component parts at the time they are retired. At December 31, 2010, we have an asset retirement obligation of $7.5 million, which is included in “Other long-term liabilities” in our consolidated balance sheets. This includes $5.8 million in asset retirement obligations acquired in connection with our Tulsa Refinery facility acquisitions in 2009 (see Note 2). Accretion expense was insignificant for the years ended December 31, 2010, 2009 and 2008.

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 and 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.

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As of December 31, 2010, our goodwill balance was $81.6 million. We recorded $32.5 million in goodwill due to our reconsolidation of HEP effective March 1, 2008. Additionally, HEP recorded $49.1 million in goodwill related to its acquisition of certain logistics and storage assets from Sinclair in December 2009 (see Note 3). Based on our impairment assessment as of December 31, 2010, we determined that the fair value of the reporting unit’s goodwill exceeded the carrying value and therefore no impairment has occurred.

In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates minimum annual cash inflows of $22.7 million and has an expected remaining term through 2035. The transportation agreement is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $2 million. At December 31, 2010, the balance of this transportation agreement was $48.5 million, net of accumulated amortization of $11.7 million, which is included in “Intangibles and other” in our consolidated balance sheets.

There were no impairments of intangible assets or goodwill during the years ended December 31, 2010, 2009 and 2008.

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 or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP’s economic performance. Additionally, since our obligation to absorb losses and receive benefits from HEP are significant to HEP, we are HEP’s primary beneficiary and therefore we consolidate HEP.

We reconsolidated HEP effective March 1, 2008, following its acquisition of our crude pipeline and tankage assets (see Note 3). Prior to March 1, 2008, we accounted for our investment in HEP using the equity method of accounting whereby we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance.

Investments in Joint Ventures: We consolidate the 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.

In March 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline that is accounted for using the equity method of accounting. As of December 31, 2010, HEP’s underlying equity in the SLC Pipeline was $61.2 million compared to its recorded investment balance of $25.4 million, a difference of $35.8 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.

Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in our consolidated balance sheets and are measured at fair value. Changes in the derivative instrument’s fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 13, Derivative Instruments and Hedging Activities for additional information.

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 25 years for refining, pipeline and terminal facilities, 5 years for transportation vehicles, 10 to 40 years for buildings and improvements and 5 to 30 years for other fixed assets.

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

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that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs.

Deferred Maintenance Costs: Our refinery units require regular major maintenance and repairs which are commonly referred to as “turnarounds”. Catalysts used in certain refinery processes also require regular “change-outs”. The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred.

Environmental Costs: Environmental costs are charged to operating expenses if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, timeframe and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

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

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

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

NOTE 2: Tulsa Refinery Acquisition

On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities that were acquired as part of the refinery assets for $40 million. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing transaction (see Note 12).

On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company (“Sinclair”) also located in Tulsa, Oklahoma for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we reimbursed Sinclair $8.4 million upon their completion of certain environmental projects at the refinery in July 2010. The refinery also produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the

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United States. We are integrating the operations of both Tulsa Refinery facilities. This will result in the Tulsa Refinery having an integrated crude processing rate of 125,000 BPSD.

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

NOTE 3: Holly Energy Partners

HEP, a consolidated VIE, is a publicly held master limited partnership that was formed to acquire, own and operate the petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support our refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. HEP also owns and operates refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas.

As of December 31, 2010, we owned a 34% interest in HEP, including the 2% general partner interest. We are HEP’s primary beneficiary and therefore we consolidate HEP. See Note 21 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 balances.

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 80% of HEP’s total revenues for the year ended December 31, 2010. We do not provide financial or equity support through any liquidity arrangements and /or guarantees to HEP.

HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes. With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse to our assets. Any recourse to HEP’s general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. See Note 12 for a description of HEP’s debt obligations.

At December 31, 2010, we have an agreement to pledge 5,000,000 of our HEP common units to collateralize certain crude oil purchases in 2011. These units represent a 22% ownership interest in HEP.

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

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

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

Roadrunner / Beeson Pipelines Transaction

Tulsa West Loading Racks Transaction

Lovington-Artesia Pipeline Transaction

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

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

SLC Pipeline Joint Venture Interest

On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. The SLC Pipeline commenced operations effective March 2009 and allows various refineries in the Salt Lake City area, including our Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. HEP’s capitalized joint venture contribution was $25.5 million.

Rio Grande Pipeline Sale

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

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


	Years Ended December 31,
	2009			2008
	(In thousands)
Income from discontinued operations before income taxes	$	5,367		$	3,716
Income tax expense		(942	)		(798	)

Income from discontinued operations, net		4,425			2,918

Gain on sale of discontinued operations before income taxes		14,479			—
Income tax expense		(1,978	)		—

Gain on sale of discontinued operations, net		12,501			—


Income from discontinued operations, net	$	16,926		$	2,918

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2008 Crude Pipelines and Tankage Transaction

On February 29, 2008, we sold certain crude pipelines and tankage assets to HEP for $180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. Consideration received consisted of $171 million in cash and 217,497 HEP common units having a fair value of $9 million. At the time of this transaction, HEP was not a consolidated entity, therefore, the assets were transferred at fair value.

Under GAAP, HEP’s acquisition of these assets qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Therefore, we reconsolidated HEP effective March 1, 2008.

The balance sheet impact of our reconsolidation of HEP on March 1, 2008 was an increase in cash of $7.3 million, an increase in other current assets of $5.9 million, an increase in properties, plant and equipment of $336.9 million, an increase in goodwill, intangibles and other assets of $86.5 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $338.5 million, an increase in deferred income taxes of $5 million, a decrease in other long-term liabilities of $0.5 million, an increase in minority interest of $389.1 million and a decrease in distributions in excess of investment in HEP of $315.1 million.

Transportation Agreements

HEP serves our refineries in New Mexico, Utah and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements.

	•		HEP PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets that we contributed to HEP upon its initial public offering in 2004);

	•		HEP IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines sold to HEP in 2005 and 2009);

	•		HEP CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets sold to HEP in 2008);

	•		HEP PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired in 2009 and 2010);

	•		HEP RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline sold to HEP in 2009);

	•		HEP ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities sold to HEP in 2009);

	•		HEP NPA (natural gas pipeline throughput agreement expiring in 2024); and

	•		HEP ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility sold to HEP in March 2010).

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HEP Equity Offerings

Transactions prior to Reconsolidation

We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under our long-term transportation agreements and our omnibus agreement with HEP. Effective March 1, 2008, we reconsolidated HEP. As a result, our financial statements include the consolidated results of HEP and intercompany transactions with HEP are eliminated. Related party transactions prior to our reconsolidation of HEP are as follows:

	•		Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008.

	•		We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 for general and administrative services under an omnibus agreement that we have with HEP that we recorded as a reduction in expenses.

	•		HEP reimbursed us for costs of employees supporting their operations of $2.1 million for the period from January 1, 2008 through February 29, 2008 which we recorded as a reduction in expenses.

	•		We received as regular distributions on our subordinated units, common units and general partner interest $6.1 million for the period from January 1, 2008 through February 29, 2008. Our distributions included $0.7 million for the period from January 1, 2008 through February 29, 2008 in incentive distributions with respect to our general partner interest.

Note 4: Financial Instruments

Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts payable, debt and derivative instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-tem maturity of these instruments.

Debt consists of outstanding principal under HEP’s $300 million revolving credit agreement (the “HEP Credit agreement”), our 9.875% senior notes due 2017 (the “Holly 9.875% Senior Notes”), HEP’s 6.25% senior notes due 2015 (the “HEP 6.25% Senior Notes”) and HEP’s 8.25% senior notes due 2018 (the “HEP 8.25% Senior Notes”). The $159 million carrying amount of outstanding debt under the HEP Credit Agreement approximates fair value as interest rates are reset frequently using current interest rates. At December 31, 2010, the estimated fair value of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $327 million, $183.2 million and $156.8 million, respectively. These fair value estimates are based on market quotes provided from a third-party bank. See Note 12 for additional information on these instruments.

Fair Value Measurements

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

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

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

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•

(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.

Our investments in marketable securities are measured at fair value using quoted market prices, a Level 1 input. See Note 7 for additional information on our investments in marketable securities, including fair value measurements.

We have commodity price swaps and HEP has an interest rate swap that are measured at fair value on a recurring basis using Level 2 inputs. With respect to these instruments, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of the respective swap agreements. The measurements are computed using market-based observable inputs, quoted forward commodity prices with respect to our commodity price swaps and the forward London Interbank Offered Rate (“LIBOR”) yield curve with respect to HEP’s interest rate swap. See Note 13 for additional information on these swap contracts, including fair value measurements.

NOTE 5: Earnings Per Share

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


	Years Ended December 31,
	2010		2009		2008
	(In thousands, except per share data)
Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	103,964	$	15,209	$	119,206


Average number of shares of common stock outstanding		53,218		50,418		50,202
Effect of dilutive stock options, variable restricted shares and performance share units		391		185		347

Average number of shares of common stock outstanding assuming dilution		53,609		50,603		50,549


Basic earnings per share from continuing operations	$	1.95	$	0.30	$	2.37

Diluted earnings per share from continuing operations	$	1.94	$	0.30	$	2.36

NOTE 6: Stock-Based Compensation

On December 31, 2010, we had three principal share-based compensation plans, that are described below (collectively, the “Long-Term Incentive Compensation Plan”). The compensation cost that has been charged against income for these plans was $9.3 million, $6.8 million and $7.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $3.6 million, $2.6 million and $2.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods. At December 31, 2010, 1,625,678 shares of common stock were reserved for future grants under the current Long-Term Incentive Compensation Plan, which reservation allows for awards of options, restricted stock, or other performance awards.

Additionally, HEP maintains share-based compensation plans for HEP directors and select Holly Logistic Services, L.L.C. executives and employees. Compensation cost attributable to HEP’s share-based compensation plans for the years ended December 31, 2010, 2009 and 2008 was $2.2 million, $1.2 million and $1.7 million, respectively.

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Stock Options

Under our Long-Term Incentive Compensation Plan and a previous stock option plan, we have granted stock options to certain officers and other key employees. All the options have been granted at prices equal to the market value of the shares at the time of the grant and normally expire on the tenth anniversary of the grant date. These awards generally vest 20% at the end of each of the five years after the grant date. There have been no options granted since December 2001. The fair value on the date of grant for each option awarded was estimated using the Black-Scholes option pricing model.

A summary of option activity and changes during the year ended December 31, 2010 is presented below:

Weighted-

Average

Aggregate

Average

Remaining

Intrinsic

Exercise

Contractual

Value

Options

Shares

Price

Term

($000)

Outstanding at January 1, 2010

40,200

2.98

Exercised

40,200

2.98

Outstanding and exercisable at December 31, 2010

—

The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008, was $1.1 million, $0.9 million and $8.6 million, respectively.

Cash received from option exercises under the stock option plans were $0.1 million, $0.1 million and $1 million, for the years ended December 31, 2010, 2009 and 2008, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $0.4 million, $0.4 million and $3.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Restricted Stock

Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and outside directors restricted stock awards with substantially all awards vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients generally have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain performance targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, was measured based on the market price as of the date of grant and is being amortized over the respective vesting period.

A summary of restricted stock activity and changes during the year ended December 31, 2010 is presented below:


				Weighted-
				Average
				Grant-Date		Aggregate Intrinsic
Restricted Stock	Grants			Fair Value		Value ($000)
Outstanding at January 1, 2010 (non-vested)		284,450		$	31.82
Vesting and transfer of ownership to recipients		(119,557	)		34.94
Granted		188,502			29.04
Forfeited		(6,399	)		27.53

Outstanding at December 31, 2010 (non-vested)		346,996		$	29.31	$	14,147

The total fair value of restricted stock vested and transferred to recipients during the years ended December 31, 2010, 2009 and 2008 was $4.2 million, $3.4 million and $2.5 million, respectively. As of December 31, 2010, there was $2.2 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 0.9 year.

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Performance Share Units

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

During the year ended December 31, 2010, we granted 110,489 performance share units having a fair value based on our grant date closing stock price of $29.17. These units are payable in stock and are subject to certain financial performance criteria.

The fair value of each performance share unit award 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, 2010, estimated share payouts for outstanding non-vested performance share unit awards ranged from 130% to 150%.

A summary of performance share unit activity and changes during the year ended December 31, 2010 is presented below:


Performance Share Units	Grants
Outstanding at January 1, 2010 (non-vested)		215,170
Vesting and transfer of ownership to recipients		(38,653	)
Granted		110,489
Forfeited		(8,913	)

Outstanding at December 31, 2010 (non-vested)		278,093

For the year ended December 31, 2010 we issued 66,483 shares of our common stock having a fair value of $2.2 million related to vested performance share units, representing a 172% payout. Based on the weighted average grant date fair value of $29.94 there was $4.5 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 1.2 years.

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

Our investment portfolio consists of cash and cash equivalents at December 31, 2010. In addition, we own 1,000,000 shares of Connacher Oil and Gas Limited common stock that was received as partial consideration upon the sale of our Montana refinery in 2006.

At times we also invest available cash in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months.

Our investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. Unrealized gains and losses, net of related income taxes, are considered temporary and are reported as a component of accumulated other comprehensive income. For investments in an unrealized loss position that are determined to be other than temporary, unrealized losses are reclassified out of accumulated other comprehensive income and into earnings as an impairment loss. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

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


	Available-for-Sale Securities
					Estimated Fair
			Gross		Value
			Unrealized		(Net Carrying
	Amortized Cost		Gain		Amount)
	(In thousands)
December 31, 2010

Equity securities	$	610	$	733	$	1,343


December 31, 2009

Equity securities	$	604	$	619	$	1,223

There were no sales or maturities of marketable securities for the year ended December 31, 2010. For the year ended December 31, 2009, we received a total of $230.3 million related to sales and maturities of marketable debt securities.

We recorded a $3.7 million impairment loss related to our investment in Connacher common stock during the year ended December 31, 2008. Although this investment in equity securities having a cost basis of $4.3 million was in an unrealized loss position for less than 12-months, we accounted for this as an other-than-temporary decline due to the severity of the loss in fair value of this investment.

NOTE 8: Inventories

Inventory consists of the following components:


	December 31,
	2010		2009
	(In thousands)
Crude oil	$	96,570	$	60,874
Other raw materials and unfinished products ⁽¹⁾		68,792		42,783
Finished products ⁽²⁾		188,274		155,925
Process chemicals ⁽³⁾		22,512		22,823
Repairs and maintenance supplies and other		24,219		21,108

Total inventory	$	400,367	$	303,513


(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 catalysts, additives and other chemicals.

The excess of current cost over the LIFO value of inventory was $284 million and $207 million at December 31, 2010 and 2009, respectively. For the year ended December 31, 2010, we recognized a $4.1 million reduction in cost of products sold. This cost reduction resulted from liquidation of certain LIFO inventory quantities that were carried at lower costs compared to 2010 LIFO inventory acquisition costs. For the year ended December 31, 2009, we recognized an $8.4 million charge to cost of products sold. This charge resulted from liquidations of certain LIFO inventory quantities that were carried at higher costs compared to 2009 LIFO inventory acquisition costs.

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NOTE 9: Properties, Plants and Equipment


	December 31,
	2010			2009
	(In thousands)
Land, buildings and improvements	$	91,169		$	73,973
Refining facilities		1,174,980			981,594
Pipelines and terminals		539,045			478,522
Transportation vehicles		20,972			20,760
Other fixed assets		83,199			80,546
Construction in progress		306,463			366,460

		2,215,828			2,001,855
Accumulated depreciation		(459,137	)		(371,885	)

	$	1,756,691		$	1,629,970

During the years ended December 31, 2010 and 2009 we capitalized $7.2 million and $3.2 million, respectively, in interest attributable to construction projects.

Depreciation expense was $94 million, $78.4 million and $53.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. Depreciation expense for the years ended December 31, 2010, 2009 and 2008 includes $27 million, $25 million and $17.5 million, respectively, of depreciation expense attributable to the operations of HEP.

NOTE 10: Joint Venture

Under a definitive agreement with Sinclair, we are jointly building 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”). Under the agreement, we own a 75% interest in the joint venture pipeline with Sinclair, our joint venture partner, owning the remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD (based on gasoline equivalents), with the capacity for further expansion to 120,000 BPD. The current total cost of the pipeline project including terminals is expected to be approximately $325 million, with our share of the cost totaling $244 million. This includes the construction of ethanol blending and storage facilities at the Cedar City terminal. We have commenced the final construction phase of the pipeline and expect the pipeline to be mechanically complete in the second quarter of 2011.

NOTE 11: Environmental Costs

Consistent with our accounting policy for environmental remediation costs, we expensed $4.2 million and $0.6 million for the years ended December 31, 2009 and 2008, respectively, for environmental remediation obligations. During 2010, we revised certain environmental accruals to reflect current cost assessments reducing our environmental accrual by $0.6 million. The accrued environmental liability reflected in the consolidated balance sheets was $26.2 million and $30.4 million at December 31, 2010 and 2009, respectively, of which $20.4 million and $24.2 million, respectively, was classified as other long-term liabilities. These accruals reflect $22.3 million of environmental obligations that we assumed in connection with our Tulsa Refinery west and east facilities acquired in 2009. Costs of future expenditures for environmental remediation that are expected to be incurred over the next several years are not discounted to their present value.

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NOTE 12: Debt

Holly Credit Agreement

We have a $400 million senior secured credit agreement expiring in March 2013 (the “Holly Credit Agreement”) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders. The Holly Credit Agreement may be used to fund working capital requirements, capital expenditures, permitted acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2010. At December 31, 2010, we had no outstanding borrowings and outstanding letters of credit totaling $71 million under the Holly Credit Agreement. At that level of usage, the unused commitment was $329 million at December 31, 2010. We entered into an amendment to the Holly Credit Agreement in May 2010 that changed certain financial covenants and provided other enhancements to the agreement.

HEP Credit Agreement

At December 31, 2010, the HEP Credit Agreement consisted of a $300 million senior secured revolving credit facility expiring in August 2011 with an outstanding balance of $159 million. On February 14, 2011, the HEP Credit Agreement was amended, slightly reducing the size of the credit facility from $300 million to $275 million (the “HEP Amended Credit Agreement”). The HEP Amended Credit Agreement expires in February 2016; provided that the HEP Amended Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the 6.25% HEP Senior Notes have not been repurchased, refinanced, extended or repaid. The HEP Amended Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes.

Holly Senior Notes Due 2017

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

HEP Senior Notes Due 2015

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

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The HEP 6.25% Senior Notes having an aggregate principle amount of $185 million mature March 1, 2015 and are registered with the SEC. The HEP 6.25% Senior Notes and HEP 8.25% 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.

Holly Financing Obligation

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

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


	December 31,			December 31,
	2010			2009
	(In thousands)
Holly 9.875% Senior Notes
Principal	$	300,000		$	300,000
Unamortized discount		(10,491	)		(11,549	)

		289,509			288,451
Holly financing obligation
Principal		38,781			39,809


Total Holly long-term debt		328,290			328,260


HEP Credit Agreement		159,000			206,000

HEP 6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(10,961	)		(13,593	)
Unamortized premium — dedesignated fair value hedge		1,444			1,791

		175,483			173,198

HEP 8.25% Senior Notes
Principal		150,000			—
Unamortized discount		(2,212	)		—

		147,788			—


Total HEP long-term debt		482,271			379,198


Total long-term debt	$	810,561		$	707,458

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NOTE 13: Derivative Instruments and Hedging Activities

Commodity Price Risk Management

We periodically enter into derivative contracts in the form of commodity price swaps to mitigate price exposure with respect to:

	•		our inventory positions;

	•		natural gas purchases;

	•		costs of crude oil; and

	•		prices of refined products.

Interest Rate Risk Management

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

As of December 31, 2010, HEP has an interest rate swap contract that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million HEP Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin of 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2010. This interest rate swap contract has been designated as a cash flow hedge and matures in February 2013.

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The following table presents balance sheet locations and related fair values of outstanding derivative instruments.


	Balance Sheet			Location of	Offsetting
Derivative Instruments	Location	Fair Value		Offsetting Balance	Amount
	(Dollars in thousands)
December 31, 2010

*Derivatives designated as cash flow hedging instruments:*

Variable-to-fixed commodity price swap contracts (forecasted volumes of natural gas purchases)	Accrued liabilities	$	38	Accumulated other comprehensive loss	$	38


Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss	$	10,026


*Derivatives not designated as hedging instruments:*

Fixed-to-variable rate swap contracts (various inventory positions)	Accrued liabilities	$	497	Cost of products sold	$	497


December 31, 2009

*Derivative designated as cash flow hedging instrument:*

Variable-to-fixed interest rate swap contract ($171 million LIBOR based debt interest payments)	Other long-term liabilities	$	9,141	Accumulated other comprehensive loss	$	9,141


*Derivatives not designated as hedging instruments:*

Fixed-to-variable interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other assets	$	2,294	Long-term debt	$	1,791	⁽¹⁾
				Equity		503	⁽²⁾

		$	2,294		$	2,294


Variable-to-fixed interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other long-term liabilities	$	2,555	Equity	$	2,555	⁽²⁾


(1)		Represents unamortized balance of a deferred hedge premium attributable to HEP’s fair value hedge that was dedesignated in 2008 that is being amortized as a reduction to interest expense over the remaining term of the HEP 6.25% Senior Notes.

(2)		Represents prior year charges to interest expense.

There was no ineffectiveness on the cash flow hedges during the periods covered in these consolidated financial statements.

NOTE 14: Income Taxes

The provision for income taxes is comprised of the following:


	Years Ended December 31,
	2010		2009			2008
	(In thousands)
Current
Federal	$	30,999	$	(24,876	)	$	27,795
State		4,473		(2,266	)		4,097
Deferred
Federal		21,796		33,269			27,727
State		2,044		4,253			5,207

	$	59,312	$	10,380		$	64,826

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


	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Tax computed at statutory rate	$	67,327		$	15,331		$	65,711
State income taxes, net of federal tax benefit		4,372			1,708			7,322
Federal tax credits		(158	)		(65	)		(1,896	)
Domestic production activities deduction		(940	)		—			(2,380	)
Tax exempt interest		—			(168	)		(2,772	)
Discontinued operations (including noncontrolling interest)		—			7,720			1,820
Noncontrolling interest in continuing operations		(11,315	)		(13,123	)		(2,739	)
Other		26			(1,023	)		(240	)

	$	59,312		$	10,380		$	64,826

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 for continuing operations as of December 31, 2010 and 2009 are as follows:


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

Total current⁽¹⁾		16,633		(11,842	)		4,791
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(207,861	)		(207,861	)
Accrued postretirement benefits		18,319		(2,558	)		15,761
Accrued environmental costs		947		—			947
Deferred turnaround costs		—		(23,326	)		(23,326	)
Investment in HEP		78,851		(4,211	)		74,640
Other		11,626		(3,722	)		7,904

Total noncurrent		109,743		(241,678	)		(131,935	)

Total	$	126,376	$	(253,520	)	$	(127,144	)


	December 31, 2009
	Assets		Liabilities			Total
	(In thousands)
Deferred taxes
Accrued employee benefits	$	7,701	$	—		$	7,701
Accrued postretirement benefits		1,812		—			1,812
Accrued environmental costs		2,339		—			2,339
Inventory differences		7,951		—			7,951
Prepayments and other		2,423		(3,321	)		(898	)

Total current⁽¹⁾		22,226		(3,321	)		18,905
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(176,889	)		(176,889	)
Accrued postretirement benefits		13,488		—			13,488
Accrued environmental costs		9,420		—			9,420
Deferred turnaround costs		—		(18,257	)		(18,257	)
Investment in HEP		47,188		(4,507	)		42,681
Other		7,512		(2,540	)		4,972

Total noncurrent		77,608		(202,193	)		(124,585	)

Total	$	99,834	$	(205,514	)	$	(105,680	)


(1)		Our net current deferred tax assets are classified as other current assets under “Prepayments and other” in our consolidated balance sheets.

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The total amount of unrecognized tax benefits as of December 31, 2010, was $2 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	Liability for
	Unrecognized
	Tax Benefits
	(In thousands)
Balance at January 1, 2010	$	1,964
Additions based on tax positions related to the current year		—
Additions for tax positions of prior years		6
Reductions for tax positions of prior years		(106	)


Balance at December 31, 2010	$	1,864

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

We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. During the year ended December 31, 2010, we recognized $0.6 million tax benefit (net of interest) as a component of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties. We do not expect that unrecognized tax benefits for tax positions taken with respect to 2010 and prior years will significantly change over the next twelve months.

We are subject to U.S. federal income tax, New Mexico, Utah and Oklahoma income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for tax years through December 31, 2005. In late 2010, the Internal Revenue Service commenced an examination of our U.S. federal tax returns for the tax years ended December 31, 2006, 2007 and 2008. We anticipate that these audits will be completed by the end of 2012.

NOTE 15: Stockholders’ Equity

Shares of our common stock outstanding and activity for the years ended December 31, 2010, 2009 and 2008 is presented below:


	Years Ended December 31,
	2010			2009			2008
Common shares outstanding at beginning of year		53,066,269			49,943,220			52,616,169
Common shares issued to Sinclair in connection with Tulsa Refinery east facility acquisition		—			2,789,155			—
Issuance of common stock upon exercise of stock options		40,200			45,000			406,000
Issuance of restricted stock, excluding restricted stock with performance feature		141,443			154,078			46,943
Vesting of performance units		70,143			146,664			84,948
Vesting of restricted stock with performance feature		6,150			49,719			57,572
Forfeitures of restricted stock		(15,042	)		(1,633	)		(2,033	)
Purchase of treasury stock⁽¹⁾		(44,475	)		(59,934	)		(3,266,379	)

Common shares outstanding at end of year		53,264,688			53,066,269			49,943,220


(1)		Includes 44,475, 59,934 and 55,515 shares purchased in 2010, 2009 and 2008, respectively, under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock.

Under a common stock repurchase program, we purchased 3,228,489 shares during the year ended December 31, 2008 at a cost of $137.1 million or an average of $42.48 per share. This program has been inactive since 2008.

During the years ended December 31, 2010, 2009 and 2008, we repurchased shares of our common stock at market price from certain employees costing $1.2 million, $1.2 million and $2 million, respectively. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

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NOTE 16: Other Comprehensive Income (Loss)

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


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

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

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


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

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

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


Year Ended December 31, 2008
Unrealized loss on available-for-sale securities	$	(169	)	$	(67	)	$	(102	)
Unrealized loss on hedging activities		(12,967	)		(2,290	)		(10,677	)
Retirement medical obligation adjustment		1,433			557			876
Minimum pension liability adjustment		(21,572	)		(8,391	)		(13,181	)

Other comprehensive loss		(33,275	)		(10,191	)		(23,084	)
Less other comprehensive loss attributable to noncontrolling interest		(7,079	)		—			(7,079	)

Other comprehensive loss attributable to Holly stockholders	$	(26,196	)	$	(10,191	)	$	(16,005	)

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

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


	December 31,
	2010			2009
	(In thousands)
Pension obligation adjustment	$	(22,672	)	$	(21,774	)
Retiree medical obligation adjustment		(1,894	)		(1,749	)
Unrealized gain on securities available-for-sale		451			379
Unrealized loss on hedging activities, net of noncontrolling interest		(2,131	)		(2,556	)

Accumulated other comprehensive loss	$	(26,246	)	$	(25,700	)

NOTE 17: Retirement Plans

Retirement Plan

We have a non-contributory defined benefit retirement plan that covers most of our employees who were hired prior to January 1, 2007. Our policy is to make contributions annually of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

The retirement plan is closed to employees hired subsequent to 2006 and not covered by collective bargaining agreements with labor unions. To the extent a non-union employee was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen.

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Effective July 1, 2010, the retirement plan was closed to all new employees covered by collective bargaining agreements with labor unions. To the extent a union employee was hired prior to July 1, 2010, the employee may elect to continue their participation in the retirement plan or to participate in our defined contribution plan whereby their participation in future benefits of the retirement plan will be frozen.

The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2010 and 2009:


	Years Ended December 31,
	2010			2009
	(In thousands)
Change in plan’s benefit obligation
Pension plan’s benefit obligation — beginning of year	$	81,170		$	74,488
Service cost		4,595			4,314
Interest cost		5,154			4,943
Benefits paid		(4,825	)		(3,726	)
Actuarial (gain) loss		7,989			1,151

Pension plan’s benefit obligation — end of year	$	94,083		$	81,170


Change in pension plan assets
Fair value of plan assets — beginning of year	$	55,618		$	45,342
Actual return on plan assets		8,297			12,977
Benefits paid		(4,825	)		(3,726	)
Employer contributions		5,400			1,025

Fair value of plan assets — end of year	$	64,490		$	55,618


Funded status
Under-funded balance	$	(29,593	)	$	(25,552	)


Amounts recognized in consolidated balance sheets
Accrued pension liability	$	(29,593	)	$	(25,552	)


Amounts recognized in accumulated other comprehensive loss
Actuarial loss	$	(33,750	)	$	(31,677	)
Prior service cost		(2,420	)		(2,811	)

Total	$	(36,170	)	$	(34,488	)

The accumulated benefit obligation was $75.4 million and $65 million at December 31, 2010 and 2009, respectively. The measurement dates used for our retirement plan were December 31, 2010 and 2009.

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


	December 31,
	2010			2009
Discount rate		5.65	%		6.20	%
Rate of future compensation increases		4.00	%		4.00	%

Net periodic pension expense consisted of the following components:


	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Service cost — benefit earned during the year	$	4,595		$	4,314		$	4,229
Interest cost on projected benefit obligations		5,154			4,943			4,692
Expected return on plan assets		(4,576	)		(3,843	)		(4,793	)
Amortization of prior service cost		390			390			390
Amortization of net loss		2,196			3,815			1,218

Net periodic pension expense	$	7,759		$	9,619		$	5,736

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


	Years Ended December 31,
	2010			2009			2008
Discount rate		6.20	%		6.50	%		6.40	%
Rate of future compensation increases		4.00	%		4.00	%		4.00	%
Expected long-term rate of return on assets		8.50	%		8.50	%		8.50	%

The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2010 are as follows:


	(In thousands)
Actuarial loss	$	2,126
Prior service cost		390

Total	$	2,516

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


				Percentage of Plan Assets at
				Year End
	Target
	Allocation			December 31,			December 31,
Asset Category	2011			2010			2009
Equity securities		62	%		66	%		69	%
Debt securities		30	%		30	%		31	%
Alternative investments		8	%		4	%		—

Total		100	%		100	%		100	%

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

The most important component of the investment strategy is the asset allocation between the various classes of securities available to the Plan for investment purposes. The current target asset allocation is 62% equity investments, 30% fixed income investments and 8% alternative investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization and international stocks. Debt investments include a blend of domestic and global debt instruments. Alternative investments include a single fund that may invest in hedge funds, private equity, debt or real estate funds or other investments. The equity and debt investments are valued using quoted market prices, a Level 1 input. The alternative investments may be valued using significant other observable or unobservable inputs, Level 2 or 3 inputs. See Note 4, Financial Instruments for information on Level 1, 2 and 3 inputs.

The overall expected long-term rate of return on Plan assets is 8.5% and is estimated using a financial simulation model of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient.

We expect to contribute between zero and $10 million to the retirement plan in 2011. Benefit payments, which reflect expected future service, are expected to be paid as follows: $6.8 million in 2011; $5.5 million in 2012; $7.1 million in 2013; $8 million in 2014; $8.2 million in 2015 and $56.1 million in 2016-2020.

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. We expensed $0.6 million, $0.7 million and $1.1 million for the years ended December 31, 2010, 2009 and 2008, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.2 million and $6.1 million at December 31, 2010 and 2009, respectively. As of December 31, 2010, the projected benefit obligation under this plan was $6.2 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.6 million in 2011; $1.1 million in 2012; $0.5 million in 2013; $1.5 million in 2014; $0.5 million in 2015 and $3 million in 2016-2020.

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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 $5.5 million, $5 million and $3.7 million for the years ended December 31, 2010, 2009 and 2008, respectively, in connection with these plans.

Postretirement Medical Plans

We adopted an unfunded postretirement medical plan as part of the voluntary early retirement program offered to eligible employees in fiscal 2000. As part of the early retirement program, we agreed to allow retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. Periodic costs under this plan have historically been insignificant. The accrued liability reflected in the consolidated balance sheets was $7.9 million and $6.6 million at December 31, 2010 and 2009, respectively, related to this plan.

NOTE 18: Lease Commitments

We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2010, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows:


	(in thousands)
2011	$	16,375
2012		14,012
2013		12,119
2014		10,966
2015		10,510
Thereafter		19,945

Total	$	83,927

Rental expense charged to operations was $13.3 million, $11.8 million and $9.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. Rental expense for the years ended December 31, 2010, 2009 and 2008 includes $7.1 million, $7.1 million and $6.5 million, respectively, of rental expense attributable to the operations of HEP.

NOTE 19: Contingencies and Contractual Obligations

In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the FERC in proceedings brought by us and other parties against SFPP, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona on SFPP’s East Line. The Court of Appeals in its May 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated as limited partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. The case was remanded to FERC and consolidated with other cases that together addressed SFPP’s rates for the period from January 1992 through May 2006. In 2003 we received an initial payment of $15.3 million from SFPP as reparations for the period from 1992 through July 2000. On April 16, 2010, a settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved the settlement on May 28, 2010. Pursuant to the settlement, we received an additional settlement payment of $8.6 million. This settlement finally resolves the amount of additional payments SFPP owes us for the period January 1992 through May 2006.

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On June 2, 2009, SFPP notified us that it would terminate the October 2008 settlement, as provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial rate increases for East Line service to become effective September 1, 2009. We and several other shippers filed protests at the FERC challenging the rate increase and asking the FERC to suspend the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending the effective date of the rate increase until January 1, 2010, on which date the rate increase was placed into effect subject to refund, and setting the rate increase for a full evidentiary hearing. The hearing was held from June 29, 2010 to August 2, 2010. On September 15, 2010, the FERC approved an interim partial settlement pursuant to which SFPP reduced its rates for the East Line service, effective September 1, 2010. The rates placed in effect on January 1, 2010, and the lower rates put into effect on September 1, 2010, remain subject to refund subject to the outcome of the evidentiary hearing. On February 10, 2011, the Administrative Law Judge that presided over the evidentiary hearing issued an initial decision holding that certain elements of SFPP’s rate increases are unjust and unreasonable. The initial decision is subject to review by the FERC and the courts. We are not in a position to predict the ultimate outcome of the rate proceeding.

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

Contractual Obligations

We have a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices over a 15-year period expiring in 2023. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term.

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

NOTE 20: Segment Information

The Refining segment includes the operations of our Navajo, Woods Cross, and Tulsa Refineries and Holly Asphalt and involves 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 Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refinery that are marketed throughout North America and are distributed in Central and South America. Holly Asphalt manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico.

The HEP segment includes all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP, a consolidated VIE, owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico, Utah and Oklahoma. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon USA, Inc., by charging fees for terminalling refined products and other hydrocarbons and storing and providing

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other services at its storage tanks and terminals. The HEP segment also includes a 25% interest in SLC Pipeline that services refineries in the Salt Lake City, Utah area. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.


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

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

Year Ended December 31, 2008
Sales and other revenues	$	5,837,449	$	94,439	$	2,641		$	(74,172	)	$	5,860,357
Depreciation and amortization	$	40,090	$	18,390	$	4,515		$	—		$	62,995
Income (loss) from operations	$	210,252	$	37,082	$	(51,654	)	$	—		$	195,680
Capital expenditures	$	381,227	$	34,317	$	2,515		$	—		$	418,059
Total assets	$	1,288,211	$	458,049	$	141,768		$	(13,803	)	$	1,874,225


(1)		The Refining segment reflects the operations of our Tulsa Refinery west and east facilities beginning on our acquisition dates of June 1, 2009 and December 1, 2009, respectively.

(2)		HEP segment revenues from external customers were $36 million, $45.5 million and $19.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.

NOTE 21: Supplemental Guarantor/Non-Guarantor Financial Information

Our obligations under the Holly 9.875% 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 34% ownership interest, and its subsidiaries (collectively, “Non-Guarantor Non-Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed these obligations.

The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of Holly Corporation (the “Parent”), the Guarantor Restricted Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Restricted Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the Non-Guarantor Restricted Subsidiaries are collectively the “Restricted Subsidiaries.”

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

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Condensed Consolidating Balance Sheet


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

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

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

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


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

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

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

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

Condensed Consolidating Balance Sheet


							Non-						Holly Corp.		Non-Guarantor
				Guarantor			Guarantor						Before		Non-Restricted
				Restricted			Restricted						Consolidation		Subsidiaries
December 31, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			of HEP⁽¹⁾		(HEP Segment)		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	127,560		$	(12,477	)	$	7,005		$	—		$	122,088	$	2,508	$	—		$	124,596
Marketable securities		—			1,223			—			—			1,223		—		—			1,223
Accounts receivable		973			759,140			—			—			760,113		18,767		(16,425	)		762,455
Intercompany accounts receivable (payable)		(1,134,296	)		817,647			316,649			—			—		—		—			—
Inventories		—			303,348			—			—			303,348		165		—			303,513
Income taxes receivable		38,071			1			—			—			38,072		—		—			38,072
Prepayments and other assets		24,940			29,018			—			—			53,958		574		(3,575	)		50,957
Current assets of discontinued operations		—			—			—			—			—		2,195		—			2,195

Total current assets		(942,752	)		1,897,900			323,654			—			1,278,802		24,209		(20,000	)		1,283,011

Properties and equipment, net		21,918			1,005,422			155,413			—			1,182,753		458,521		(11,304	)		1,629,970
Investment in subsidiaries		2,010,510			435,970			(314,973	)		(2,131,507	)		—		—		—			—
Intangibles and other assets		8,752			64,017			—			—			72,769		159,045		1,144			232,958

Total assets	$	1,098,428		$	3,403,309		$	164,094		$	(2,131,507	)	$	2,534,324	$	641,775	$	(30,160	)	$	3,145,939


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,968		$	974,177		$	2,224		$	—		$	985,369	$	6,211	$	(16,425	)	$	975,155
Accrued liabilities		23,752			15,477			709			—			39,938		13,594		(3,575	)		49,957

Total current liabilities		32,720			989,654			2,933			—			1,025,307		19,805		(20,000	)		1,025,112

Long-term debt		288,451			57,151			—			—			345,602		379,198		(17,342	)		707,458
Non-current liabilities		37,859			30,795			—			—			68,654		12,349		—			81,003
Deferred income taxes		119,127			229			278			—			119,634		—		4,951			124,585
Distributions in excess of inv in HEP		—			314,970			—			—			314,970		—		(314,970	)		—
Equity — Holly Corporation		620,271			2,010,510			160,883			(2,171,393	)		620,271		230,423		(231,655	)		619,039
Equity — noncontrolling interest		—			—			—			39,886			39,886		—		548,856			588,742

Total liabilities and equity	$	1,098,428		$	3,403,309		$	164,094		$	(2,131,507	)	$	2,534,324	$	641,775	$	(30,160	)	$	3,145,939

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Condensed Consolidating Statement of Income


							Non-						Holly Corp.			Non-Guarantor
				Guarantor			Guarantor						Before			Non-Restricted
				Restricted			Restricted						Consolidation			Subsidiaries
Year Ended December 31, 2010	Parent			Subsidiaries			Subsidiaries			Eliminations			of HEP			(HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	412		$	8,287,000		$	3		$	—		$	8,287,415		$	182,114		$	(146,600	)	$	8,322,929

Operating costs and expenses:
Cost of products sold		—			7,510,172			185			—			7,510,357			—			(143,208	)		7,367,149
Operating expenses		2,411			449,534			32			—			451,977			52,947			(510	)		504,414
General and administrative expenses		62,130			990			—			—			63,120			7,719			—			70,839
Depreciation and amortization		3,745			85,517			(113	)		—			89,149			29,062			(682	)		117,529


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


Income (loss) from operations		(67,874	)		240,787			(101	)		—			172,812			92,386			(2,200	)		262,998

Other income (expense):
Equity in earnings of subsidiaries and joint venture		265,367			30,036			30,069			(295,403	)		30,069			2,393			(30,069	)		2,393
Interest income (expense)		(33,838	)		(5,456	)		45			—			(39,249	)		(36,245	)		2,466			(73,028	)


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

Income from continuing operations before income taxes		163,655			265,367			30,013			(295,403	)		163,632			58,534			(29,803	)		192,363

Income tax provision		59,016			—			—			—			59,016			296			—			59,312


Net income		104,639			265,367			30,013			(295,403	)		104,616			58,238			(29,803	)		133,051

Less net income attributable to noncontrolling interest		—			—			—			23			23			—			(29,110	)		(29,087	)


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

Condensed Consolidating Statement of Income


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

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


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


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

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


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


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

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


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

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


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

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


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

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Condensed Consolidating Statement of Income


						Non-						Holly Corp.		Non-Guarantor
				Guarantor		Guarantor						Before		Non-Restricted
				Restricted		Restricted						Consolidation		Subsidiaries
Year Ended December 31, 2008	Parent			Subsidiaries		Subsidiaries			Eliminations			of HEP		(HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	1,831		$	5,838,244	$	15		$	—		$	5,840,090	$	94,439		$	(74,172	)	$	5,860,357

Operating costs and expenses:
Cost of products sold		23			5,354,561		—			—			5,354,584		—			(73,885	)		5,280,699
Operating expenses		17			231,995		627			—			232,639		33,353			(287	)		265,705
General and administrative expenses		46,230			3,434		—			—			49,664		5,614			—			55,278
Depreciation and amortization		3,627			40,299		679			—			44,605		18,390			—			62,995


Total operating costs and expenses		49,897			5,630,289		1,306			—			5,681,492		57,357			(74,172	)		5,664,677


Income (loss) from operations		(48,066	)		207,955		(1,291	)		—			158,598		37,082			—			195,680

Other income (expense):
Equity in earnings of subsidiaries		257,587			15,700		16,633			(273,287	)		16,633		—			(13,643	)		2,990
Interest income (expense)		(23,875	)		31,698		507			—			8,330		(21,488	)		—			(13,158	)
Net gain (loss)		—			2,234		—			—			2,234		—			—			2,234


		233,712			49,632		17,140			(273,287	)		27,197		(21,488	)		(13,643	)		(7,934	)


Income (loss) from continuing operations before income taxes		185,646			257,587		15,849			(273,287	)		185,795		15,594			(13,643	)		187,746

Income tax provision		64,537			—		—			—			64,537		238			(747	)		64,028


Income from continuing operations		121,109			257,587		15,849			(273,287	)		121,258		15,356			(12,896	)		123,718

Income from discontinued operations		—			—		—			—			—		3,665			(747	)		2,918


Net income		121,109			257,587		15,849			(273,287	)		121,258		19,021			(13,643	)		126,636

Less net income attributable to noncontrolling interest		—			—		—			149			149		—			(6,227	)		(6,078	)


Net income attributable to Holly Corporation stockholders	$	121,109		$	257,587	$	15,849		$	(273,138	)	$	121,407	$	19,021		$	(19,870	)	$	120,558

Condensed Consolidating Statement of Cash Flows


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

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


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


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


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


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


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

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Condensed Consolidating Statement of Cash Flows


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

Cash flows from investing activities
Additions to properties, plants and equipment — Holly		(2,904	)		(215,343	)		(51,305	)		(269,552	)		(25,665	)		—			(295,217	)
Additions to properties, plants and equipment — HEP		—			—			—			—			(128,079	)		95,080			(32,999	)
Purchases of marketable securities		(175,892	)		—			—			(175,892	)		—			—			(175,892	)
Sales and maturities of marketable securities		230,281			—			—			230,281			—			—			230,281
Acquisition of Tulsa Refineries — Holly		74,000			(341,141	)		—			(267,141	)		—			—			(267,141	)
Investment in SLC Pipeline		—			—			—			—			(25,500	)		—			(25,500	)
Proceeds from the sale of assets		—			83,280			—			83,280			—			(83,280	)		—
Proceeds from sale of Rio Grande		—			—			—			—			31,865			—			31,865


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


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


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


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


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

Condensed Consolidating Statement of Cash Flows


							Non-			Holly Corp.			Non-Guarantor
				Guarantor			Guarantor			Before			Non-Restricted
				Restricted			Restricted			Consolidation			Subsidiaries
Year Ended December 31, 2008	Parent			Subsidiaries			Subsidiaries			of HEP			(HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(63,480	)	$	192,299		$	364		$	129,183		$	46,091		$	(19,784	)	$	155,490

Cash flows from investing activities
Additions to properties, plants and equipment — Holly		(2,515	)		(295,937	)		(85,290	)		(383,742	)		—			—			(383,742	)
Additions to properties, plants and equipment — HEP		—			—			—			—			(34,317	)		—			(34,317	)
Purchases of marketable securities		(769,142	)		—			—			(769,142	)		—			—			(769,142	)
Sales and maturities of marketable securities		945,461			—			—			945,461			—			—			945,461
Proceeds from sale of crude pipeline and tankage assets		—			171,000			—			171,000			—			—			171,000
Proceeds from sale of HPI		—			5,958			—			5,958			—			—			5,958
Increase in cash due to consolidation of HEP		—			—			—			—			—			7,295			7,295
Investment in HEP		—			(290	)		—			(290	)		—			—			(290	)


Net cash provided by (used for) investing activities		173,804			(119,269	)		(85,290	)		(30,755	)		(34,317	)		7,295			(57,777	)


Cash flows from financing activities
Net borrowings under credit agreement		—			—			—			—			29,000			—			29,000
Issuance of common stock upon exercise of options		1,005			—			—			1,005			—			—			1,005
Dividends		(29,054	)		—			—			(29,054	)		—			(10	)		(29,064	)
Distributions to noncontrolling interest		—			—			—			—			(41,603	)		19,505			(22,098	)
Purchase of treasury stock		(151,106	)		—			—			(151,106	)		—			—			(151,106	)
Contribution from joint venture partner		(1,500	)		(55,500	)		74,000			17,000			—			—			17,000
Excess tax benefit from equity based compensation		5,694			—			—			5,694			—			—			5,694
Deferred financing costs					(800	)		—			(800	)		(113	)		—			(913	)
Purchase of units for restricted grants		—			—			—			—			(795	)		—			(795	)


Net cash provided by (used for) financing activities		(174,961	)		(56,300	)		74,000			(157,261	)		(13,511	)		19,495			(151,277	)


Cash and cash equivalents
Increase (decrease) for the period		(64,637	)		16,730			(10,926	)		(58,833	)		(1,737	)		7,006			(53,564	)
Beginning of period		97,953			(17,912	)		14,328			94,369			7,006			(7,006	)		94,369


End of period	$	33,316		$	(1,182	)	$	3,402		$	35,536		$	5,269		$	—		$	40,805

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NOTE 22: Significant Customers

All revenues are domestic revenues, except for sales of gasoline and diesel fuel for export into Mexico by the Refining segment. The export sales were to an affiliate of PEMEX and accounted for $323.2 million (4%) of our revenues in 2010, $188.6 million (4%) of our revenues in 2009 and $325.4 million (6%) of our revenues in 2008. In 2010, Sinclair accounted for $1,616 million or 19% of our revenues. We have several other significant customers, none of which accounted for more than 10% of our revenues in 2009 and 2008.

NOTE 23: Quarterly Information (Unaudited)


	First			Second		Third		Fourth
	Quarter			Quarter		Quarter		Quarter			Year
	(In thousands, except per share data)
Year Ended December 31, 2010
Sales and other revenues	$	1,874,290		$	2,145,860	$	2,090,988	$	2,211,791		$	8,322,929
Operating costs and expenses	$	1,897,034		$	2,013,696	$	1,983,370	$	2,165,831		$	8,059,931
Income (loss) from operations	$	(22,744	)	$	132,164	$	107,618	$	45,960		$	262,998
Income (loss) from continuing operations before income taxes	$	(39,926	)	$	112,320	$	90,884	$	29,085		$	192,363
Net income (loss) attributable to Holly Corporation stockholders	$	(28,094	)	$	66,162	$	51,177	$	14,719		$	103,964
Net income (loss) per share attributable to Holly Corporation stockholders—basic	$	(0.53	)	$	1.24	$	0.96	$	0.28		$	1.95
Net income (loss) per share attributable to Holly Corporation stockholders—diluted	$	(0.53	)	$	1.24	$	0.96	$	0.27		$	1.94
Dividends per common share	$	0.15		$	0.15	$	0.15	$	0.15		$	0.60
Average number of shares of common stock outstanding
Basic		53,094			53,206		53,210		53,258			53,218
Diluted		53,232			53,408		53,567		53,648			53,609

Year Ended December 31, 2009
Sales and other revenues	$	648,030		$	1,035,778	$	1,488,491	$	1,661,969		$	4,834,268
Operating costs and expenses	$	610,239		$	998,327	$	1,432,909	$	1,712,482		$	4,753,957
Income (loss) from operations	$	37,791		$	37,451	$	55,582	$	(50,513	)	$	80,311
Income (loss) from continuing operations before income taxes	$	33,923		$	29,260	$	43,674	$	(63,054	)	$	43,803
Net income (loss) attributable to Holly Corporation stockholders	$	21,945		$	14,605	$	23,484	$	(40,501	)	$	19,533
Net income (loss) per share attributable to Holly Corporation stockholders—basic	$	0.44		$	0.29	$	0.47	$	(0.79	)	$	0.39
Net income (loss) per share attributable to Holly Corporation stockholders — diluted	$	0.44		$	0.29	$	0.47	$	(0.79	)	$	0.39
Dividends per common share	$	0.15		$	0.15	$	0.15	$	0.15		$	0.60
Average number of shares of common stock outstanding
Basic		50,042			50,170		50,244		51,200			50,418
Diluted		50,171			50,226		50,327		51,380			50,603

NOTE 24: Subsequent Events

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination of us and Frontier Oil Corporation (“Frontier”). Subject to the terms and conditions of the merger agreement which has been approved unanimously by both our and Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of Holly common stock for each share of Frontier common stock if the merger is completed. Completion of the merger is subject to certain conditions, including, among others, (i) approval by our stockholders of the issuance of our common stock to Frontier’s stockholders in connection with the merger, (ii) adoption of the merger agreement by Frontier’s stockholders, (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the registration statement on Form S-4 used to register the common stock to be issued as consideration for the merger having been declared effective by the SEC and (v) the entry into a new credit facility for the combined company.

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

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

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Exchange Act as of the end of the period covered by this annual report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2010.

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 2010 that would need to be reported on Form 8-K that have not previously been reported.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and d(5) of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 12, 2011 and is incorporated herein by reference.

New York Stock Exchange Certification

In 2010, Matthew P. Clifton, as our Chief Executive Officer, provided to the New York Stock Exchange the annual CEO certification regarding our compliance with the New York Stock Exchange’s corporate governance listing standards.

Item 11. Executive Compensation

The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 12, 2011 and is incorporated herein by reference.

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PART IV

Item 15. Exhibits and 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		74

Consolidated Balance Sheets at December 31, 2010 and 2009		75

Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008		76

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		77

Consolidated Statements of Equity for the years ended December 31, 2010, 2009 and 2008		78

Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008		79

Notes to Consolidated Financial Statements		80

(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 114 to 120 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.


	HOLLY CORPORATION (Registrant)
	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chief Executive Officer

Date: February 25, 2011

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/ Matthew P. Clifton Matthew P. Clifton	Chief Executive Officer and Chairman of the Board	February 25, 2011

/s/ Bruce R. Shaw Bruce R. Shaw	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 25, 2011

/s/ Scott C. Surplus Scott C. Surplus	Vice President and Controller (Principal Accounting Officer)	February 25, 2011

/s/ Denise C. McWatters Denise C. McWatters	Vice President, General Counsel and Secretary	February 25, 2011

/s/ Buford P. Berry Buford P. Berry	Director	February 25, 2011

/s/ Leldon E. Echols Leldon E. Echols	Director	February 25, 2011

/s/ Robert G. McKenzie Robert G. McKenzie	Director	February 25, 2011

/s/ Jack P. Reid Jack P. Reid	Director	February 25, 2011

/s/ Paul T. Stoffel Paul T. Stoffel	Director	February 25, 2011

/s/ Tommy A. Valenta Tommy A. Valenta	Director	February 25, 2011

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HOLLY CORPORATION

INDEX TO EXHIBITS

Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K


Exhibit
Number		Description

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

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

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

3.1+		Restated Certificate of Incorporation of Holly Corporation, dated March 10, 2010.

3.2		By-Laws of Holly Corporation, dated December 22, 2005 (incorporated by reference to Exhibit 3.2.2 of Registrant’s Current Report on Form 8-K filed December 22, 2005, File No. 1-03876).

4.1		Indenture, dated June 10, 2009, among Holly Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee, relating to Holly Corporation’s 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued thereunder) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated June 11, 2009, File No. 1-03876).

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

4.3		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).

4.4		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).

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

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Exhibit
Number		Description

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

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

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

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

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

4.11		Seventh Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage- Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

4.12		Eighth Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

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

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

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

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Exhibit
Number		Description

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

10.2+		First Amendment to Option Agreement, dated February 11, 2010, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P.

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

10.4+		Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C., and HEP Logistics GP, L.L.C.

10.5+		Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC.

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

10.7+		Amendment to Tulsa Equipment and Throughput Agreement, dated December 9, 2010, among Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC.

10.8+		Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing — Tulsa, LLC and Holly Refining & Marketing Company LLC.

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

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

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Exhibit
Number		Description

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

10.12+		Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing-Woods Cross and Holly Refining & Marketing Company LLC.

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

10.14+		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.

10.15		First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated March 31,2010, by and among Holly Refining & Marketing-Tulsa, LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed April 6, 2010, File No. 1-03876).

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

10.17+		Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing-Tulsa LLC and Holly Refining & Marketing Company LLC.

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

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

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

-117-


Exhibit
Number		Description

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

10.22		Fourth Amended and Restated Omnibus Agreement, dated March 31, 2010, by and among Holly Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed April 6, 2010, File No. 1-03876).

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

10.24*		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).

10.25*		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).

10.26*		Amendment No. 1 to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated on May 24, 2007 (incorporated by reference to Exhibit 10.5 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).

10.27*		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).

10.28*		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).

10.29*		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).

10.30*		Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed January 12, 2007, File No. 1-03876).

10.31*		First Amendment to Performance Share Unit Agreement (incorporated by reference to Exhibit 10.16 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).

10.32*		Holly Corporation Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

10.33*		Holly Corporation Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

-118-


Exhibit
Number		Description

10.34*		Holly Energy Partners, L.P. Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

10.35*		Form of Executive Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.36*		Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.37*		Form of Director Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).

10.38*		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).

10.39*		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).

10.40*		Executive Restricted Stock Agreement, dated March 12, 2010, by and between Holly Corporation and Matthew P. Clifton (incorporated by reference to Exhibit 10.8 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).

10.41*		Executive Restricted Stock Agreement, dated March 12, 2010, by and between Holly Corporation and David L. Lamp (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).

10.42*		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).

10.43		Second Amended and Restated Credit Agreement dated April 7, 2009, by and among Holly Corporation and Bank of America, N.A., as administrative agent, swing line lender, and L/C issuer, UBS Loan Finance LLC and U.S. Bank National Association, as co-documentation agents, Union Bank of California, N.A. and Compass Bank, as syndication agents, and certain other lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-03876).

10.44		Confirmation of Commitments [reflects increases in commitments on November 3, 2009 and December 4, 2009 under the Second Amended and Restated Credit Agreement filed (incorporated by reference to Exhibit 10.33 of Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-03876).

-119-


Exhibit
Number		Description

10.45		First Amendment to Second Amended and Restated Credit Agreement, dated May 6, 2010, by and among Holly Corporation, as the borrower, the Guarantors party thereto, Bank of America, N.A., as administrative agent, and each of the financial institutions parties thereto as lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed with May 11, 2010, File No. 1-03876).

10.46		Reaffirmation and Assumption Agreement, dated March 14, 2008, among Holly Corporation, the subsidiaries identified therein, the additional grantors identified therein and Bank of America, N.A. (adding additional grantors under the Guaranty and Collateral Agreement included as Exhibit 10.49 below) (incorporated by reference to Exhibit 10.22 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).

10.47		Guarantee and Collateral Agreement, dated July 1, 2004, among Holly Corporation and certain of its Subsidiaries in favor of Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-03876).

10.48		First Amendment to Guarantee and Collateral Agreement and Reaffirmation and Assumption Agreement, dated April 7, 2009, by and among Holly Corporation and certain of its subsidiaries, in favor of Bank of America, N.A., as administrative agent, for certain other lenders from time to time party to the Second Amended and Restated Credit Agreement dated April 7, 2009 (incorporated by reference to Exhibit 10.5 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-03876).

10.49		Amendment No. 2 to the Guarantee and Collateral Agreement, dated as of May 6, 2010, among Holly Corporation, each Subsidiary of the Holly Corporation from time to time party thereto and Bank of America, N.A. as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed May 11, 2010, File No. 1-03876).

10.50		Amended and Restated Credit Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger, Bank of America, N.A., as syndication agent, Guaranty Bank, as documentation agent and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed October 31, 2007, File No. 1-32225).

10.51		Agreement and Amendment No. 1 to Amended and Restated Credit Agreement, dated February 25, 2008, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners’ Current Report on Form 8-K filed February 27, 2008, File No. 1-32225).

10.52		Amendment No. 2 to Amended and Restated Credit Agreement, dated September 8, 2008, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries acting as guarantors, Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.11 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q filed October 31, 2008, File No. 1-32225).

-120-


Exhibit
Number		Description

10.53		Amended and Restated Pledge Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.12 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225).

10.54		Amended and Restated Guaranty Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.13 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225).

10.55		Amended and Restated Security Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.14 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225).

10.56		Form of Mortgage, Deed of Trust, Security Agreement, Assignment of Rents and Leases, Fixture Filing and Financing Statement (for purposes of granting security interests in real property in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.15 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225).

10.57*		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).

21.1+		Subsidiaries of Registrant.

23.1+		Consent of Independent Registered Public Accounting Firm.

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

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

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

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

101++		The following financial information from Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Comprehensive Income, and (vi) Notes to the Consolidated Financial Statements (tagged as blocks of text).


+		Filed herewith.

++		Furnished electronically herewith.

*		Constitutes management contracts or compensatory plans or arrangements.

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Item		Page
PART I

Forward-looking statements			3

Definitions			4

1 and 2.	Business and properties		8
1A.	Risk factors		28
1B.	Unresolved staff comments		41
3.	Legal proceedings		41
4.	(Removed and reserved)		43

PART II

5.	Market for the Registrant’s common equity, related stockholder matters and issuer purchases of equity securities		44
6.	Selected financial data		45
7.	Management’s discussion and analysis of financial condition and results of operations		46
7A.	Quantitative and qualitative disclosures about market risk		65

Reconciliations to amounts reported under generally accepted accounting principles			65

8.	Financial statements and supplementary data		71
9.	Changes in and disagreements with accountants on accounting and financial disclosure		110
9A.	Controls and procedures		110
9B.	Other information		110

PART III

10.	Directors, executive officers and corporate governance		110
11.	Executive compensation		110
12.	Security ownership of certain beneficial owners and management and related stockholder matters		111
13.	Certain relationships, related transactions and director independence		111
14.	Principal accountant fees and services		111

PART IV

15.	Exhibits and financial statement schedules		112

Signatures			113

Index to exhibits			114
EX-3.1
EX-10.2
EX-10.4
EX-10.5
EX-10.7
EX-10.8
EX-10.12
EX-10.14
EX-10.17
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


	Page
	Reference
SDWA		26
SFPP		12
SLC Pipeline		9
Sinclair		8
Sinclair Tulsa		43
Sunoco		8
Tulsa Refinery		8
Tulsa Refinery east facility		8
Tulsa Refinery west facility		8
UNEV Pipeline		9
VIE		8
Woods Cross Refinery		9
WRB		13