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

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

For the transition period from                      to                     

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.

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.

 

 

TABLE OF CONTENTS

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

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.

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.

     “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.

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

		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

Terms used in the financial statements and footnotes are as defined therein.

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,

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.

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	%

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	%

		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	%

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.

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.

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

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	%

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.

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	%

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. 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.

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	%

		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

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.

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.

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.

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

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

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.

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.

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

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.

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

Insurance

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

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

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

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.

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.

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

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

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.

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

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

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

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

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.

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.

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

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.

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.

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

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

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

(“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)

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.

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

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

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

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