UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2008

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 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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act). (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, 2008 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $1,494 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.)

50,069,998 shares of Common Stock, par value $.01 per share, were outstanding on February 6, 2009.

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 14, 2009, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2008, are incorporated by reference in Part III.

 

 

TABLE OF CONTENTS

		Page
Item
PART I
Forward-Looking Statements			3
Definitions			4
1 and 2. Business and properties			7
1A. Risk factors			22
1B. Unresolved staff comments			31
3. Legal proceedings			31
4. Submission of matters to a vote of security holders			34
PART II
5. Market for the Registrant’s common equity, related stockholder matters and issuer purchases of equity securities			35
6. Selected financial data			36
7. Management’s discussion and analysis of financial condition and results of operations			37
7A. Quantitative and qualitative disclosures about market risk			55
Reconciliations to amounts reported under generally accepted accounting principles			55
8. Financial statements and supplementary data			61
9. Changes in and disagreements with accountants on accounting and financial disclosure			93
9A. Controls and procedures			93
9B. Other information			93
PART III
10. Directors, executive officers and corporate governance			93
11. Executive compensation			93
12. Security ownership of certain beneficial owners and management and related stockholder matters			94
13. Certain relationships, related transactions and director independence			94
14. Principal accountant fees and services			94
PART IV
15. Exhibits and financial statement schedules			95
Signatures			96
Index to exhibits			98
EX-3.2
EX-3.3
EX-10.4
EX-10.5
EX-10.10
EX-10.16
EX-10.22
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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 belief 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 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 future acquired operations;
	•		the possibility of terrorist attacks and the consequences of any such attacks;
	•		general economic conditions; and
	•		other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation in conjunction with the forward-looking statements included in this Form 10-K 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).

     “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 the 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 slightly above atmospheric pressure the vapor back to liquid in order to purify, fractionate or form the desired products.

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

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

     “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.

     “MMBtu” or one million British thermal units, means for each unit, the amount of heat required to raise one pound of water one degree Fahrenheit at one atmosphere pressure.

     “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.

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

     “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.

     “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 below atmospheric pressure the vapor back to 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
2004 ACT			49
2005 ACT			49
Amended NOV			32
AOC			32
CAA			20
CERCLA			21
Connacher			8
Court of Appeals			31
Credit Agreement			45
Crude Pipelines and Tankage Assets			7
CWA			20
DESC			13
EBITDA			40
EPA			13
Exchange Act			94
FASB			7
FERC			17
FIN			7
Fixed Rate Swap			54
GAAP			8
HEP			7
HEP CPTA			17
HEP Credit Agreement			45
HEP IPA			17
HEP PTA			17
HEP Senior Notes			46
Holly Asphalt			11
HPI			19
LIBOR			54
LIFO			30
MDEQ			32
Montana Refinery			8
Navajo Refinery			7
NEP			33
NMED			32
NPDES			20
Ominbus Agreement			13
OSHA			33
PEMEX			9
Plains			11
Plan			89
PPI			17
Rio Grande			7
Rocky Mountain			33
SEC			7
SDWA			20
SFAS			53
SFPP			11
SLC Pipeline			19
South System			19
UNEV Pipeline			16
UOSH			33
Variable Rate Swap			54
VIE			7
VRDN			45
Woods Cross Refinery			7
WRB			11

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. 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 and jet fuel. 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.”

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 and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

On February 29, 2008, we closed on the sale of certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0 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 both of our 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. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.

HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standard Board (“FASB”) Interpretation (“FIN”) No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

As of December 31, 2008, we:

•

owned and operated two 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 known as the “Navajo Refinery”), and a refinery in Woods Cross, Utah (“Woods Cross Refinery”);

	•		owned and operated Holly Asphalt Company (formerly, NK Asphalt Partners) which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and
	•		owned a 46% interest in HEP (which includes our 2% general partnership interest), which has logistics assets including approximately 2,600 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; two refinery truck rack facilities; a refined products tank farm facility; on-site crude oil tankage at both our Navajo and Woods Cross Refineries and a 70% interest in Rio Grande.

Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns the Navajo Refinery. The Navajo Refinery has a crude capacity of 85,000 BPSD, can process up to approximately 90% 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. This facility is a high conversion refinery that processes regional sweet and Canadian sour crude oils.

On March 31, 2006 we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). Accordingly, the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale are shown in discontinued operations.

Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation).

REFINERY OPERATIONS

Our refinery operations include the Navajo Refinery and the Woods Cross Refinery. The following table sets forth information, including performance measures about our refinery operations that are not calculations based upon U.S. generally accepted accounting principles (“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 Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. Information regarding our individual refineries is provided later in this section of “Refinery Operations.”

		Years Ended December 31,
		2008				2007				2006
Consolidated(8)
Crude charge (BPD) (1)			100,680				103,490				96,570
Refinery production (BPD) (2)			110,850				113,270				105,730
Sales of produced refined products (BPD)			111,950				115,050				105,090
Sales of refined products (BPD) (3)			120,750				126,800				119,870
Refinery utilization (4)			89.7	%			94.1	%			92.4	%
Average per produced barrel (5)
Net sales		$	108.83			$	89.77			$	80.21
Cost of products(6)			97.87				73.03				64.43
Refinery gross margin			10.96				16.74				15.78
Refinery operating expenses (7)			5.14				4.43				4.83
Net operating margin		$	5.82			$	12.31			$	10.95
Feedstocks:
Sour crude oil			63	%			62	%			61	%
Sweet crude oil			23	%			23	%			25	%
Black wax crude oil			4	%			3	%			3	%
Other feedstocks and blends			10	%			12	%			11	%
Total			100	%			100	%			100	%

Set forth below is information regarding our principal products.

		Years Ended December 31,
		2008				2007				2006
Consolidated
Sales of produced refined products:
Gasolines			58	%			60	%			61	%
Diesel fuels			32	%			29	%			28	%
Jet fuels			1	%			2	%			3	%
Fuel oil			3	%			4	%			3	%
Asphalt			3	%			2	%			2	%
LPG and other			3	%			3	%			3	%
Total			100	%			100	%			100	%

We have several significant customers, none of which accounts for more than 10% of our business. 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 domestic airline use. 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 current crude oil capacity of 85,000 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 91% of its raw materials throughput into high value light products. For 2008, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 57%, 33% and 1%, 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,
		2008				2007				2006
Navajo Refinery
Crude charge (BPD) (1)			79,020				79,460				72,930
Refinery production (BPD) (2)			88,680				87,930				80,540
Sales of produced refined products (BPD)			89,580				88,920				79,940
Sales of refined products (BPD) (3)			97,320				100,460				93,660
Refinery utilization (4)			93.0	%			94.6	%			92.9	%
Average per produced barrel (5)
Net sales		$	108.52			$	89.68			$	79.62
Cost of products(6)			98.97				74.10				64.25
Refinery gross margin			9.55				15.58				15.37
Refinery operating expenses (7)			4.58				4.30				4.74
Net operating margin		$	4.97			$	11.28			$	10.63
Feedstocks:
Sour crude oil			79	%			82	%			80	%
Sweet crude oil			10	%			9	%			8	%
Other feedstocks and blends			11	%			9	%			12	%
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, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 2.0 million barrels of feedstock and product tankage at the site of which 0.2 million is 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 an integrated 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 is owned by HEP. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of two 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 facilities is 85,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.

We also own 67 crude oil trucks and 67 trailers that support operations at our Navajo Refinery facilities.

We distribute refined products from the Navajo Refinery to markets in Arizona, New Mexico and west Texas primarily through two of HEP’s owned pipelines that extend from Artesia, New Mexico to El Paso, Texas. 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.

We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Texas and northern Mexico under Holly Asphalt Company (“Holly Asphalt”). We have three manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico and Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo Refinery and third-party suppliers. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our Navajo and Woods Cross Refineries and third-party suppliers. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.

Markets and Competition

The Navajo Refinery primarily serves the growing southwestern United States market, 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 All American Pipeline, L.P. (“Plains”) and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan’s SFPP, L.P. (“SFPP”). In addition, the Navajo Refinery transports petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via HEP’s pipelines running from Artesia to San Juan County, New Mexico.

El Paso Market

The El Paso market for refined products is currently supplied by a number of area refiners, gulf coast refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between ConocoPhillips and EnCana Corp.), Valero, Alon, and Western Refining. Pipelines serving this market include Longhorn, Magellan, NuStar and HEP pipelines. Refined products from the Gulf Coast are transported via the Longhorn and Magellan pipelines. We currently supply approximately 11,000 BPD to the El Paso market, which accounts for approximately 18% of the refined products consumed in that 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 West Coast. We currently supply approximately 52,000 BPD of refined products via the SFPP Pipeline into the Arizona market, comprised primarily of Phoenix and Tucson, which accounts for approximately 17% of the refined products consumed in that market.

New Mexico Markets

The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western, Alon and WRB. We currently supply approximately 22,000 BPD of refined products to the New Mexico market, which accounts for approximately 20% of the refined products consumed in that market.

The common carrier pipeline we use to serve the Albuquerque market out of El Paso currently operates at near capacity. 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 provide a total of up to 45,000 BPD of light products to the growing Albuquerque and Santa Fe, New Mexico areas. If needed, additional pump stations could further increase the pipeline’s capabilities.

The Longhorn Pipeline is a 72,000 BPD common carrier pipeline that has the ability to deliver 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. In 2008, Longhorn Partners Pipeline, L.P., owner of the pipeline, filed for

bankruptcy and has put the pipeline up for sale. Flying J, the pipeline’s major shipper also filed for bankruptcy in 2008. The status of current shipping levels is presently unknown.

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.

Crude Oil and Feedstock Supplies

The Navajo Refinery is situated near the Permian Basin in an area that historically has had abundant supplies of crude oil available both for regional users, such as us, and for export to other areas. We purchase crude oil from producers in nearby southeastern New Mexico and west Texas and from major oil companies. Crude oil is gathered both through HEP’s pipelines and our tank trucks and through third-party crude oil pipeline systems. Crude oil acquired in locations distant from the refinery is exchanged for crude oil that is transportable to the refinery.

We also purchase isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery. In 2008, approximately 4,900 BPD of isobutane and 5,000 BPD of natural gasoline used in the Navajo Refinery’s operations were purchased from a newly operational fractionation facility in Hobbs, New Mexico, which is owned by Enterprise Products, L.P. as well as volumes purchased from the mid-continent area and 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 two parallel 65-mile pipelines running from Lovington to Artesia. From time to time, we also purchase gas oil, naphtha and light cycle oil from other oil companies for use as feedstock.

Principal Products and Customers

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

		Years Ended December 31,
		2008				2007				2006
Navajo Refinery
Sales of produced refined products:
Gasolines			57	%			59	%			60	%
Diesel fuels			33	%			30	%			28	%
Jet fuels			1	%			3	%			4	%
Fuel oil			3	%			3	%			2	%
Asphalt			3	%			2	%			3	%
LPG and other			3	%			3	%			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 use. All asphalt produced at the Navajo Refinery and third-party purchased asphalt is marketed through Holly Asphalt to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing.

Military jet fuel is sold to the Defense Energy Support Center, a part of the United States Department of Defense (the “DESC”), under a series of one-year contracts that can vary significantly from year to year. We sold approximately 775 BPD of jet fuel to the DESC in 2008. We have had a military jet fuel supply contract with the United States Government for each of the last 39 years. Our size in terms of employees and refining capacity allows us to bid for military jet fuel sales contracts under a small business set-aside program. In September 2008, the DESC awarded us contracts for sales of military jet fuel for the period from October 1, 2008 through September 30,

2009. Our total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, is 12.7 million gallons as compared to the total award for the 2007-2008 contract year of 22.0 million gallons.

Capital Improvement Projects

We have invested significant amounts in capital expenditures in recent years to expand and enhance the Navajo Refinery and expand our supply and distribution network.

Our Board of Directors approved a capital budget for 2009 of $11.4 million for refining improvement projects at the Navajo Refinery, not including the capital projects approved in prior years or our expansion and feedstock flexibility projects described below.

At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant, and the expansion of our Lovington crude and vacuum units. Phase I is expected to be mechanically complete in the first quarter of 2009 and was originally estimated to cost $163.0 million. The total cost of phase I is now expected to be approximately $185.0 million. The added costs are associated with permit timing delays, scope changes due to permit required pollution control equipment that was not anticipated, material cost escalation and increased labor rates.

Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 and was originally estimated to cost $84.0 million. The total cost of phase II is now expected to be approximately $96.0 million. The added costs are associated with better scope definition on the Artesia crude and vacuum unit revamp portion of the overall project and material cost escalation.

We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $15.0 million and are expected to be completed at the same time as the phase II project.

The Navajo Refinery is also installing a new 100 ton per day sulfur recovery unit that is scheduled for mechanical completion in the first quarter of 2009. The project was originally estimated to cost $26.0 million and is now projected to cost $31.0 million. The added costs are associated permit delays, material cost escalation and increased labor rates.

Once the Navajo projects discussed above are complete, the Navajo Refinery will be able to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt with all their performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks and enable the refinery to meet new LSG specifications required by the Environmental Protection Agency (“EPA”).

In July 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion’s pipeline from Cushing, Oklahoma to its Slaughter Station located in west Texas. Our Board of Directors has approved capital expenditures of up to $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico and a 65-mile pipeline from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline project that connects HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. Under the provisions of our omnibus agreement with HEP (the “Omnibus Agreement”), HEP will have an option to purchase these transportation assets upon our completion of these projects. We expect to complete these projects in the fourth quarter of 2009.

Woods Cross Refinery

Facilities

The Woods Cross Refinery has a crude oil 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 is located in Woods Cross, Utah and processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2008, gasoline and diesel fuel (excluding volumes purchased for resale) represented 63% and 29%, 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 Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

		Years Ended December 31,
		2008				2007				2006
Woods Cross Refinery
Crude charge (BPD) (1)			21,660				24,030				23,640
Refinery production (BPD) (2)			22,170				25,340				25,190
Sales of produced refined products (BPD)			22,370				26,130				25,150
Sales of refined products (BPD) (3)			23,430				26,340				26,210
Refinery utilization (4)			79.5	%			92.4	%			90.9	%
Average per produced barrel (5)
Net sales		$	110.07			$	90.09			$	82.09
Cost of products (6)			93.47				69.40				64.99
Refinery gross margin			16.60				20.69				17.10
Refinery operating expenses (7)			7.42				4.86				5.13
Net operating margin		$	9.18			$	15.83			$	11.97
Feedstocks:
Sour crude oil			1	%			2	%			2	%
Sweet crude oil			72	%			75	%			79	%
Black wax crude oil			21	%			15	%			10	%
Other feedstocks and blends			6	%			8	%			9	%
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 is 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.

We own and operate 2 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 allow 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 60% 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 currently supply approximately 16,000 BPD of refined products into the Utah market, which represents approximately 15% of the refined products consumed in that market, to branded and unbranded customers.

Idaho, Wyoming, Eastern Washington and Nevada Markets

We currently supply approximately 7,000 BPD of refined products into the Idaho, Wyoming, eastern Washington and Nevada markets, which represents approximately 2% of the refined products consumed in those markets. Woods Cross 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 the Woods Cross Refinery:

		Years Ended December 31,
		2008				2007				2006
Woods Cross Refinery
Sales of produced refined products:
Gasolines			63	%			63	%			63	%
Diesel fuels			29	%			27	%			28	%
Jet fuels			—	%			2	%			2	%
Fuel oil			5	%			5	%			5	%
Asphalt			1	%			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 is sold for domestic airline use. All asphalt produced is blended to fuel oil and sold locally, railed to the Gulf Coast, railed directly to our customers or marketed through Holly Asphalt Company 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 primarily from suppliers in Canada, Wyoming, Utah and Colorado via common carrier pipelines that originate in Canada, Wyoming and Colorado. Supplies of black wax crude oil are shipped via truck.

Capital Improvement Projects

Our approved capital budget for 2009 capital projects at the Woods Cross Refinery is $5.3 million not including the major projects described below or other capital projects approved in prior years.

At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipment and black wax unloading systems. The total cost of this project was approximately $122.0 million versus our original $105.0 million estimate. Increased costs resulted from offsite scope additions, material cost escalation and increased labor rates. The projects were completed in the fourth quarter of 2008. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.

To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. HEP’s joint venture pipeline with Plains will permit the transportation of additional crude oil into the Salt Lake City area. HEP’s joint venture project with Plains is further described under the HEP section of this discussion of business and properties.

In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the “UNEV Pipeline”). Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million, with our share of the cost totaling $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered into 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. Additionally in 2008, we purchased a terminal and rail facility located near Cedar City, Utah that will serve as a key component of our UNEV joint venture pipeline.

The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.

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 and Arizona and a 70% interest in Rio Grande.

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, 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.

Transportation Agreements

HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (the “HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (the “HEP IPA”). Under these agreements, we pay HEP fees to transport and store volumes of refined product on HEP’s pipelines and terminal facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change equal to 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 equal to the percentage change in PPI, but not below the initial tariff rate. Following the July 1, 2008 PPI rate adjustment, minimum payments under the HEP PTA and the HEP IPA are $41.2 million and $13.3 million, respectively, for the twelve months ending June 30, 2009.

In connection with our sale of the Crude Pipelines and Tankage Assets to HEP, we entered into a 15-year crude pipelines and tankage agreement with HEP (the “HEP CPTA”). Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the PPI, but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a FERC adjustment factor. Additionally, we amended the Omnibus Agreement with HEP to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.

HEP also has a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on HEP’s pipelines and throughput through their terminals volumes of refined products that results in a minimum level of annual revenue. Under the Alon PTA, the agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

As of December 31, 2008, HEP’s contractual minimum revenues under long-term service agreements are as follows:

		Minimum Annualized
		Commitment			Year of
Agreement		(In millions)			Maturity		Contract Type
HEP PTA(1)		$	41.2		2019		Minimum revenue commitment
HEP IPA(1)			13.3		2020		Minimum revenue commitment
HEP CPTA(1)			26.8		2023		Minimum revenue commitment
Alon PTA(2)			22.0		2020		Minimum volume commitment
Alon capacity lease(2)			6.8		Various		Capacity lease
Total		$	110.1

As of December 31, 2008, 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;
	•		two parallel 65-mile pipelines that transport intermediate feedstocks and crude oil from our Lovington, New Mexico refinery facilities to our Artesia, New Mexico refining facilities;
	•		approximately 860 miles of crude oil trunk, gathering and connection pipelines located in west Texas and New Mexico that deliver crude oil to our Navajo Refinery;
	•		approximately 10 miles of crude oil and refined product pipelines that support our Woods Cross Refinery near Salt Lake City, Utah; and
	•		a 70% interest in Rio Grande, a joint venture that owns a 249-mile refined product pipeline that transports liquid petroleum gases, or LPG’s, from west Texas to the Texas/Mexico border near El Paso for further transport into northern Mexico.

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 1.0 million 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;
	•		two refined product truck loading racks, one located within our Navajo Refinery that is permitted to load over 40,000 BPD of light refined products, and one located within our Woods Cross Refinery near Salt Lake City, Utah, that is permitted to load over 25,000 BPD of light refined products.
	•		a Roswell, New Mexico jet fuel terminal leased through September 2011; and
	•		on-site crude oil tankage at our Navajo and Woods Cross Refineries having an aggregate storage capacity of approximately 600,000 barrels.

Capital Improvement Projects

HEP’s capital budget for 2009 is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of HEP’s pipeline system between Artesia, New Mexico and El Paso, Texas (the “South System”) and the joint venture with Plains discussed below.

In October 2007, we amended the HEP PTA under which HEP has agreed to expand their South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at HEP’s El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. HEP expects to complete the majority of this project in early 2009.

In November 2007, HEP executed a definitive agreement with Plains to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area (the “SLC Pipeline”). Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by HEP. HEP expects to purchase their 25% interest in the joint venture in March 2009 when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including our Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah that is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of HEP’s investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to us upon the closing of their investment in the SLC Pipeline.

HEP is currently working on a capital improvement project that will provide increased flexibility and capacity to their intermediate pipelines enabling them to accommodate increased volumes following the completion of our Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $5.1 million.

Also, HEP is currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline at an estimated cost of $1.9 million for completion in early 2009.

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

We lease our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires June 30, 2011, requires lease payments of approximately $115,000 per month plus certain operating expenses and provides for one five-year renewal period. 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.

Exploration and Production

A subsidiary, Holly Petroleum, Inc. (“HPI”) previously conducted a small-scale oil and gas exploration and production program. We sold substantially all of the oil and gas properties in 2008 for $6.0 million, resulting in a gain of $6.0 million.

Employees and Labor Relations

As of December 31, 2008, we had 978 employees, of which 339 are currently covered by collective bargaining agreements. We consider our employee relations to be good. We successfully renegotiated the collective bargaining agreement for our Utah refinery and extended the term to 2012 in February, 2009 (subject only to ongoing efforts to document the interim letter agreement with formal contract terms) and the collective bargaining agreement for our New Mexico refinery expires in 2010.

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.

In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal CAA liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement for a Consent Decree. The agreement was signed by the parties and approved and entered by the federal district court in Utah in 2008. It includes obligations for us to make specified additional capital investments currently estimated to total approximately $17.0 million over several years and to make changes in operating procedures at the refinery. The agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit to the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the anticipated settlement.

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. For example, 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. Both of our refineries met the ultimate 15 PPM standard for both our non-road and highway diesel fuel by June 1, 2006. Although the highway and non-road diesel sulfur regulations provided for a timed phase-in of the low sulfur requirements with extended compliance dates for small refiners such as us, we met these standards by the earliest deadline for large refiners. This entailed substantial capital expenditures. Also, by January 1 2011, we will be required to meet another EPA regulation limiting the average concentration of sulfur in gasoline to 30 PPM. Our current capital projects include plant modifications and enhancements that will enable us to meet this new LSG requirement.

We are currently making plans to comply with new EPA regulations on gasoline that will impose further reductions in the benzene content of our produced gasoline and would mandate the blending of prescribed, substantial percentages of renewable fuels (e.g. ethanol) into our produced gasoline. Both of these initiatives contain mitigating provisions for small refiners such as us. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may cause us to make substantial capital expenditures 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 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. 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 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, 2008 we had an accrual of $7.3 million related to such environmental liabilities of which $4.2 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 formed 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.

In addition, we currently process volumes of lower cost crude oils, such as regional sour, heavy Canadian and Black Wax. As part of our current capital initiatives, we plan on providing additional flexibility to both our Navajo and Woods Cross Refineries that will allow us to process a greater degree of these lower cost crude oils. In recent years, the spread or differential between these lower cost heavy/sour crude oils and higher priced light/sweet crude oils has widened. A substantial or prolonged decrease in these crude oil differentials could negatively impact our earnings and cash flows.

We may not be able to successfully execute our business strategies to grow our business.

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; 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 or spills) affecting our facilities, or those of vendors and suppliers; shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; and/or nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project. These projects may not be completed on schedule or at all or at the budgeted cost. 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.

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 every three to five years, 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. The Woods Cross refinery turnaround occurred in August/September, 2008, and the Navajo refinery turnaround occurred in January/February, 2009.

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. There is growing consensus that some form of regulation will be forthcoming at the federal level in the United States with respect to greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides). Also, new federal or state legislation or regulatory programs that restrict emissions of greenhouse gases 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.”

Insufficient ethanol supplies or disruption in ethanol supply may disrupt our ability to market ethanol blended fuels.

If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits.

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

The renewal or replacement of existing sales agreements with our customers 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.

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

In order to maintain or increase production levels at our refineries, we must continually contract for new 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 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 potential operation of new refined product transportation pipelines or disruption or proration of existing pipelines could impact the supply of refined products to our existing markets, including El Paso, Albuquerque and Phoenix.

If one of the major refined products pipelines becomes inoperative, we would be required to keep refined products in inventory or supply refined products to our customers through an alternative pipeline or by additional tanker trucks from the refinery, which could increase our costs and result in a decline in profitability. The Longhorn Pipeline is an approximately 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. Longhorn Pipeline is a wholly-owned subsidiary of Flying J Inc. On December 22, 2008, both Longhorn Pipeline and Flying J Inc. filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. The status of current shipping levels is currently unknown. The future ownership and operation of the Longhorn Pipeline is uncertain pending resolution of the bankruptcy proceedings. Increased supplies of refined product delivered by the Longhorn Pipeline and Kinder Morgan’s El Paso to Phoenix pipeline could result in additional downward pressure on wholesale refined product prices and refined product margins in El Paso, Arizona and related markets.

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

In addition to the projects described above, other projects have been explored from time to time by refiners and other entities which if completed, could result in further increases in the supply of products to our markets. For example, competitors may rely on alternate methods of transportation, such as trucking, to increase the volume of refined products entering our markets. Such alternatives may decrease the price of refined products or decrease our ability to market our refined products in those markets.

In the case of the Albuquerque market, the common carrier pipeline we use to serve this market out of El Paso currently operates at near capacity. However, through our relationship with HEP, our Navajo Refinery has pipeline access to the Albuquerque vicinity and to Bloomfield, New Mexico, that will permit us to deliver a total of up to 45,000 BPD of light products to these locations, thereby eliminating the risk of future pipeline constraints on shipments to Albuquerque. If needed, additional pump stations could further increase HEP’s pipeline capabilities. Any future pipeline constraints or disruptions affecting our ability to transport refined products to Arizona or Albuquerque could, if sustained, adversely affect our results of operations and financial condition.

For additional information on competition in our markets due to new product transportation pipelines or proration of existing pipelines, see “Markets and Competition” under the “Navajo Refinery” discussion under Items 1 and 2, “Business and Properties.”

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 46% 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 and Utah under three 15-year pipelines and terminals and tankage agreements expiring in 2019 through 2023. 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 subsidiary. 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.”

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

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as 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. 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.

If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.

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, 2008, approximately 35% of our employees were represented by labor unions under collective bargaining agreements expiring in 2009 through 2010. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.

We are exposed to the credit risks of our key customers.

We are subject to risks of loss resulting from nonpayment or nonperformance by our 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.

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.

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.

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 full capacity. Our failure to operate our refineries at full 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 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 full capacity.

An unfavorable credit profile 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. 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 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 full capacity. A failure to operate our refineries at full 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, or at all. 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.

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 $10.0 million to $20.0 million to the retirement plan in 2009. 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, 2008, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7 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.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

Item 3. Legal Proceedings

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. 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 by 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 income tax issue and the other remaining issues relating to SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding covering the period from 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. A partial settlement covering the period June 2006 through November 2007, which became final in February 2008, resulted in a payment from SFPP to us of approximately $1.3 million in April 2008. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through November 2010. The Commission approved the settlement on January 29, 2009. The settlement will reduce SFPP’s current rates and require SFPP to make additional payments to us of approximately $2.0 million.

Our Navajo Refining Company subsidiary was named as a defendant, along with approximately 40 other companies involved in oil refining and marketing and related businesses, in a lawsuit originally filed in May 2006 by the State of New Mexico in the U.S. District Court for the District of New Mexico and subsequently transferred to the U.S. District Court for the Southern District of New York under multidistrict procedures along with approximately 100 similar cases, in which Navajo is not named, brought by other governmental entities and private parties in other states. The lawsuit, in which Navajo is named, as amended in October 2006 through the filing of a second amended complaint, alleges that the defendants are liable for contaminating the waters of New Mexico through producing and/or supplying MTBE or gasoline or other products containing MTBE. The lawsuit asserts claims for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy, and seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. The second amended complaint also contains a claim, asserted against certain other defendants but not against Navajo, alleging violations of certain provisions of the Toxic Substances Control Act, which appears to be similar to a claim previously threatened in a mailing to Navajo and other defendants by law firms representing the plaintiffs. Most other defendants have been dismissed from this lawsuit as a result of settlements. As of the close of business on the day prior to the date of this report, Navajo has not been served in this lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

In May 2008, Montana Refining Company, our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser in March 2006, and the unrelated company that purchased the refinery from MRC, entered into a Notice Of Violation And Administrative Order On Consent (“AOC”) with the Montana Department of Environmental Quality (“MDEQ”). The AOC relates to assertions by the MDEQ that the Great Falls refinery exceeded limitations on sulfur dioxide in the refinery’s air emission permit on certain dates in 2004 and 2005 and in 2006 both before and after the sale of the refinery, erroneously certified compliance with limitations on sulfur dioxide emissions, failed to promptly report emissions limit deviations, exceeded limits on sulfur in fuel gas on specified dates in 2005, failed in 2005 to conduct timely testing for certain emissions, submitted late a report required to be submitted in early 2006, failed to achieve a specified limitation on certain emissions in the first three quarters of 2006, and failed to timely submit a report on a 2005 emissions test. The AOC requires certain actions to be taken by the refinery and payment of a $105,000 penalty. Pursuant to the terms of the AOC, a lawsuit on this matter brought by the MDEQ in Montana state court was dismissed with prejudice in late May 2008. We paid the current owner of the Great Falls refinery $126,700 which represents our appropriate share of penalty and related amounts with respect to this matter.

In October 2008, the New Mexico Environment Department (“NMED”) issued an Amended Notice of Violation and Proposed Penalties (“Amended NOV”) to Navajo Refining Company, amending an NOV issued in February 2007. The NOV is a preliminary enforcement document issued by NMED and usually is the predicate to formal administrative or judicial enforcement. The February 2007 NOV was issued following two hazardous waste compliance evaluation inspections at the Artesia, New Mexico refinery that were conducted in April and November

2006 and alleged violations of the New Mexico Hazardous Waste Management Regulations and Navajo’s Hazardous Waste Permit. NMED proposed a civil penalty of approximately $0.1 million for the February 2007 NOV. The Amended NOV includes additional alleged violations concerning post-closure care of a hazardous waste land treatment unit and the construction of a tank on the land treatment area. The Amended NOV also proposes an additional civil penalty of $0.3 million. Navajo has submitted responses to the February 2007 NOV and the Amended NOV, challenging certain alleged violations and proposed penalty amounts and is continuing negotiations with the NMED to resolve these matters expeditiously.

Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries are named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in state district court in Davis County, Utah involving a construction dispute regarding the installation of improvements known as a crude desalter, crude unloader, and west tank farm at our Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the construction of those improvements for which the plaintiff was not paid. The claims made against our subsidiaries are for breach of contract, lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the amount of $2.3 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the Refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Triad Engineers Limited d/b/a Triad Project Corporation, answered the complaint denying any liability, and asserted counterclaims. We intend to vigorously defend against the claims asserted in the lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries are named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in the U.S. District Court for the Central District of Utah involving a construction related dispute over the installation of an oil gas hydrocracker at the Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the installation of the oil gas hydrocracker for which the plaintiff was not paid. The claims made against our subsidiaries are for lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the approximate amount of $12.0 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Benham Constructors, LLC, and have filed an answer to the complaint denying any liability. We intend to vigorously defend against the claims asserted in the lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

Prior to the sale by Holly Corporation of the Montana Refining Company 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 Montana Refining and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against Montana Refining and other companies for response costs of $298,500 in connection with its cleanup efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of Environmental Quality directing Montana Refining and other companies to complete a remedial investigation and a request by the MDEQ that Montana Refining and other companies pay $147,500 to reimburse the State’s costs for remedial actions. Montana Refining Company has denied responsibility for the requested EPA and MDEQ cleanup actions and the MDEQ and Coast Guard response costs.

On February 17, 2009, our Holly Refining & Marketing Company filed a complaint with the FERC against Plains and Rocky Mountain Pipeline LLC (“Rocky Mountain”). Plains and Rocky Mountain are affiliated companies which operate an interstate crude oil pipeline system from origin points in the Rocky Mountain region to destination points in the Rocky Mountain region. The Holly refinery at Salt Lake City uses that pipeline system to supply between 15,000 to 17,000 barrels per day of its crude oil requirements. Holly’s complaint alleges that the proposed reversal of flow on the segment of the pipeline system from Ft. Laramie, Wyoming, to Wamsutter, Wyoming, will provide an undue and unjust preference for affiliates of Plains and Rocky Mountain and will be unduly and unjustly prejudicial and discriminatory against Holly in violation of the Interstate Commerce Act. The complaint seeks an order requiring Plains and Rocky Mountain to cease and desist from the proposed reversal of flow and an award of damages to Holly for any injury caused by the reversal. Plains and Rocky Mountain have not yet answered the

complaint. At this time, it is not known whether the FERC will assert jurisdiction over the complaint or will find that the complaint warrants discovery and hearing. Without the benefit of discovery, it is not possible to determine the likelihood of obtaining relief, including the likelihood or amount of any damages.

In June 2007, the Federal Occupational Safety and Health Administration (“OSHA”) announced a national emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As a part of the NEP, OSHA encouraged the State Plan States such as Utah to initiate their own version of the NEP. Beginning on May 1, 2008, the Utah Labor Commission, Occupational Safety and Health Division (“UOSH”) began an inspection of the refinery which is operated by Holly Refining and Marketing Company — Woods Cross and is located in Woods Cross, Utah. The inspection ended on September 18 and on October 23, 2008, UOSH issued one citation alleging 33 violations of various safety standards including the Process Safety Management Standard and proposing a penalty of $91,750. We filed a notice of contest with the Adjudicative Division, Utah Labor Commission, in Salt Lake City, Utah. On February 18, 2009, the initial status conference for this matter was held and a scheduling order will issue shortly. Our answer is due on March 4th and discovery will continue until July 6, 2009. No hearing date has been set. We intend to vigorously defend this citation and believe that we have strong defenses on the merits.

We are a party to various other litigation and proceedings not mentioned in this report 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. Submission of Matters to a Vote of Security Holders

No matter was submitted to a vote of security holders during the fourth quarter of 2008.

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
2008
First Quarter		$	56.81			$	38.84			$	0.15				79,892,000
Second Quarter		$	49.62			$	36.13			$	0.15				79,585,500
Third Quarter		$	37.47			$	25.88			$	0.15				88,195,700
Fourth Quarter		$	28.83			$	10.84			$	0.15				81,694,000
2007
First Quarter		$	61.80			$	48.28			$	0.10				44,985,000
Second Quarter		$	77.53			$	57.83			$	0.12				45,298,000
Third Quarter		$	80.55			$	51.61			$	0.12				54,029,000
Fourth Quarter		$	67.39			$	45.00			$	0.12				62,577,000

As of February 6, 2009, we had approximately 21,500 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 limits the payment of dividends. See Note 11 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”

Under our common stock repurchase program, repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. There were no common stock repurchases during the fourth quarter of 2008.

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 Form 10-K.

		Years Ended December 31,
		2008(1)				2007(1)				2006(1)(3)				2005(1)(2)(3)				2004(2)(3)
		(In thousands, except per share data)
FINANCIAL DATA
For the period
Sales and other revenues		$	5,867,668			$	4,791,742			$	4,023,217			$	3,046,313			$	2,116,245
Income from continuing operations before income taxes			185,384				499,444				383,501				263,652				136,929
Income tax provision			64,826				165,316				136,603				99,626				53,985
Income from continuing operations			120,558				334,128				246,898				164,026				82,944
Income from discontinued operations, net of taxes			—				—				19,668				2,963				935
Net income before cumulative effect of change in accounting principle			120,558				334,128				266,566				166,989				83,879
Cumulative effect of accounting change (net of income tax expense of $426)			—				—				—				669				—
Net income		$	120,558			$	334,128			$	266,566			$	167,658			$	83,879
Net income per common share — basic		$	2.40			$	6.09			$	4.68			$	2.72			$	1.34
Net income per common share — diluted		$	2.38			$	5.98			$	4.58			$	2.65			$	1.30
Cash dividends declared per common share		$	0.60			$	0.46			$	0.29			$	0.19			$	0.145
Average number of common shares outstanding:
Basic			50,202				54,852				56,976				61,728				62,780
Diluted			50,549				55,850				58,210				63,244				64,340
Net cash provided by operating activities		$	155,490			$	422,737			$	245,183			$	251,234			$	164,604
Net cash provided by (used for) investing activities		$	(57,777	)		$	(293,057	)		$	35,805			$	(320,135	)		$	(194,003	)
Net cash provided by (used for) financing activities		$	(151,277	)		$	(189,428	)		$	(175,935	)		$	50,505			$	85,169
At end of period
Cash, cash equivalents and investments in marketable securities		$	96,008			$	329,784			$	255,953			$	254,842			$	219,265
Working capital		$	68,465			$	216,541			$	240,181			$	210,103			$	159,839
Total assets		$	1,874,225			$	1,663,945			$	1,237,869			$	1,142,900			$	982,713
Total debt, including current maturities and borrowings under credit agreements		$	370,914			$	—			$	—			$	—			$	33,572
Stockholders’ equity		$	541,540			$	593,794			$	466,094			$	377,351			$	339,916

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. 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 two refineries in Artesia and Lovington, New Mexico (operated as one refinery) and Woods Cross, Utah. As of December 31, 2008, our refineries had a combined crude capacity of 116,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2008, we also owned a 46% interest in HEP, which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande.

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel and jet fuel in markets in the southwestern and western United States. Our sales and other revenues and net income for the year ended December 31, 2008 were $5,867.7 million and $120.6 million, respectively. Our sales and other revenues and net income for the year ended December 31, 2007 were $4,791.7 million and $334.1 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the year ended December 31, 2008 were $5,667.3 million, an increase from $4,325.4 million for the year ended December 31, 2007.

On February 29, 2008, we closed on the sale of the Crude Pipelines and Tankage Assets to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.

In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with HEP. Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the PPI, but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the FERC Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a FERC adjustment factor. Additionally, we amended the Omnibus Agreement to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.

HEP is a VIE as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage 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%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

On March 31, 2006 we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. We have presented the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale in discontinued operations.

Under our common stock repurchase program, repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million or an average of $42.48 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.

RESULTS OF OPERATIONS

Financial Data

		Years Ended December 31,
		2008				2007				2006
		(In thousands, except per share data)
Sales and other revenues		$	5,867,668			$	4,791,742			$	4,023,217
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)			5,280,699				4,003,488				3,349,404
Operating expenses (exclusive of depreciation and amortization)			267,570				209,281				208,460
General and administrative expenses (exclusive of depreciation and amortization)			54,906				68,773				63,255
Depreciation and amortization			63,789				43,456				39,721
Exploration expenses, including dry holes			372				412				486
Total operating costs and expenses			5,667,336				4,325,410				3,661,326
Income from operations			200,332				466,332				361,891
Other income (expense):
Equity in earnings of Holly Energy Partners			2,990				19,109				12,929
Minority interest in earnings of Holly Energy Partners			(7,041	)			—				—
Impairment of equity securities			(3,724	)			—				—
Gain on sale of HPI			5,958				—				—
Interest income			10,824				15,089				9,757
Interest expense			(23,955	)			(1,086	)			(1,076	)
			(14,948	)			33,112				21,610
Income from continuing operations before income taxes			185,384				499,444				383,501
Income tax provision			64,826				165,316				136,603
Income from continuing operations			120,558				334,128				246,898
Income from discontinued operations, net of taxes			—				—				19,668
Net income		$	120,558			$	334,128			$	266,566
Basic earnings per share:
Continuing operations		$	2.40			$	6.09			$	4.33
Discontinued operations			—				—				0.35
Net income		$	2.40			$	6.09			$	4.68
Diluted earnings per share:
Continuing operations		$	2.38			$	5.98			$	4.24
Discontinued operations			—				—				0.34
Net income		$	2.38			$	5.98			$	4.58
Cash dividends declared per common share		$	0.60			$	0.46			$	0.29
Average number of common shares outstanding:
Basic			50,202				54,852				56,976
Diluted			50,549				55,850				58,210

Balance Sheet Data

		Years Ended December 31,
		2008				2007
		(In thousands)
Cash, cash equivalents and investments in marketable securities		$	96,008			$	329,784
Working capital		$	68,465			$	216,541
Total assets		$	1,874,225			$	1,663,945
Long-term debt — HEP		$	341,914			$	—
Stockholders’ equity		$	541,540			$	593,794

Other Financial Data

		Years Ended December 31,
		2008				2007				2006
		(In thousands)
Net cash provided by operating activities		$	155,490			$	422,737			$	245,183
Net cash provided by (used for) investing activities		$	(57,777	)		$	(293,057	)		$	35,805
Net cash used for financing activities		$	(151,277	)		$	(189,428	)		$	(175,935	)
Capital expenditures		$	418,059			$	161,258			$	120,429
EBITDA from continuing operations (1)		$	262,304			$	528,897			$	414,541

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

		Years Ended December 31,
		2008				2007				2006
		(In thousands)
Sales and other revenues
Refining(1)		$	5,837,449			$	4,790,164			$	4,021,974
HEP(2)			101,750				—				—
Corporate and other			2,641				1,578				1,752
Eliminations			(74,172	)			—				(509	)
Consolidated		$	5,867,668			$	4,791,742			$	4,023,217
Operating income (loss)
Refining(1)		$	210,252			$	537,118			$	425,474
HEP(2)			41,734				—				—
Corporate and other			(51,654	)			(70,786	)			(63,583	)
Consolidated		$	200,332			$	466,332			$	361,891

Refining Operating Data

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

		Years Ended December 31,
		2008				2007				2006
Consolidated (8)
Crude charge (BPD) (1)			100,680				103,490				96,570
Refinery production (BPD) (2)			110,850				113,270				105,730
Sales of produced refined products (BPD)			111,950				115,050				105,090
Sales of refined products (BPD) (3)			120,750				126,800				119,870
Refinery utilization (4)			89.7	%			94.1	%			92.4	%
Average per produced barrel (5)
Net sales		$	108.83			$	89.77			$	80.21
Cost of products (6)			97.87				73.03				64.43
Refinery gross margin			10.96				16.74				15.78
Refinery operating expenses (7)			5.14				4.43				4.83
Net operating margin		$	5.82			$	12.31			$	10.95

Results of Operations — Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Summary

Net Income for the year ended December 31, 2008 was $120.6 million ($2.40 per basic and $2.38 per diluted share) compared to $334.1 million ($6.09 per basic and $5.98 per diluted share) for the year ended December 31, 2007. Net income for the year ended December 31, 2008 decreased $213.5 million compared to the year ended December 31, 2007 due principally to reduced refined product margins during the first half of 2008. Overall refinery gross margins from continuing operations for the year ended December 31, 2008 were $10.96 per produced barrel compared to $16.74 for the year ended December 31, 2007.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 23% from $4,791.7 million for the year ended December 31, 2007 to $5,867.7 million for the year ended December 31, 2008 due principally to higher refined product sales prices, partially offset by a 5% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold increased 21% from $89.77 for the year ended December 31, 2007 to $108.83 for the year ended December 31, 2008. The decrease in volumes of refined products sold was principally due to the effects of downtime at our refineries during the second quarter and a scheduled major maintenance turnaround at our Woods Cross Refinery during the third quarter of 2008. Additionally, sales and other revenues for the year ended December 31, 2008 include $27.6 million in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties due to our reconsolidation of HEP effective March 1, 2008. Sales and other revenues for 2007 include $23.0 million in sulfur credit sales.

Cost of Products Sold

Cost of products sold increased 32% from $4,003.5 million in 2007 to $5,280.7 million in 2008 due principally to significantly higher crude oil costs in the first half of 2008. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 34% from $73.03 in 2007 to $97.87 in 2008. This increase was partially offset by the effects of a 5% decrease in year-over-year volumes of refined products sold.

Gross Refinery Margins

Gross refining margin per produced barrel decreased 35% from $16.74 in 2007 to $10.96 in 2008 due to an increase in the average we paid per produced barrel of crude oil and feedstocks, partially offset by the effects of an increase in the average sales price we received per produced barrel sold. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.

Operating Expenses

Operating expenses, exclusive of depreciation and amortization increased 28% from $209.3 million in 2007 to $267.6 million in 2008 due principally to the inclusion of $35.2 million in operating costs attributable to HEP as a result of our reconsolidation effective March 1, 2008. Additionally, higher refinery utility and payroll costs along with increased maintenance costs associated with unplanned downtime contributed to this increase.

General and Administrative Expenses

General and administrative expenses decreased 20% from $68.8 million in 2007 to $54.9 million in 2008 due principally to a decrease in equity-based compensation expense which is to some extent affected by our stock price. Additionally, general and administrative expenses for 2008 include $5.6 million in expenses related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Depreciation and Amortization Expenses

Depreciation and amortization increased 47% from $43.5 million in 2007 to $63.8 million in 2008 due principally to the inclusion of $19.2 million in depreciation and amortization related to HEP operations following our reconsolidation of HEP effective March 1, 2008 and depreciation attributable to capitalized refinery improvement projects in 2008 and 2007.

Equity in Earnings of HEP

Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP was $3.0 million and $19.1 million for the years ended December 31, 2008 and 2007, respectively.

Minority Interests

Minority interests in income for the year ended December 31, 2008 reduced our income by $7.0 million and represents the noncontrolling interest in HEP’s earnings.

Impairment of equity securities

Impairment of equity securities represents an impairment loss of $3.7 million during the year ended December 31, 2008 that relates to 1,000,000 shares of Connacher common stock that was received in connection with our sale of the Montana Refinery in 2006 and we accounted for this as an other-than-temporary decline in the fair value of these securities.

Gain on sale of HPI

We sold substantially all of the oil and gas properties of HPI, a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6.0 million, resulting in a gain of $6.0 million.

Interest Income

Interest income for the year ended December 31, 2008 was $10.8 million compared to $15.1 million for the year ended December 31, 2007 due principally to the effects of a lower interest rate environment combined with a decrease in investments in marketable debt securities.

Interest Expense

Interest expense was $24.0 million for the year ended December 31, 2008 compared to $1.1 million for the year ended December 31, 2007. The increase in interest expense was due principally to the inclusion of $21.5 million in interest expense related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Income Taxes

Income taxes decreased 61% from $165.3 million in 2007 to $64.8 million in 2008 due to lower pre-tax earnings in 2008 compared to 2007. The effective tax rate for the year ended December 31, 2008 was 35.0% compared to 33.1% for the year ended December 31, 2007. We realized a lower effective tax rate during 2007 due principally to a higher utilization of ULSD tax credits in 2007 that were fully utilized in 2008.

Results of Operations — Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Summary

Income from continuing operations for the year ended December 31, 2007 was $334.1 million ($6.09 per basic and $5.98 per diluted share) compared to $246.9 million ($4.33 per basic and $4.24 per diluted share) for the year ended December 31, 2006. Net income from continuing operations increased by 35% or $87.2 million for the year ended December 31, 2007 compared to the year ended December 31, 2006 due principally to an overall increase in refined product margins during the first half of 2007 combined with an increase in volumes of produced refined products sold, partially offset by an increase in total operating costs and expenses and an overall decrease in refined product margins during the second half of the year. Overall sales of produced refined products from continuing operations for the year ended December 31, 2007 increased 9% compared to the year ended December 31, 2006. Overall refinery gross margins from continuing operations for the year ended December 31, 2007 were $16.74 per produced barrel compared to $15.78 for the year ended December 31, 2006.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 19% from $4,023.2 million for the year ended December 31, 2006 to $4,791.7 million for the year ended December 31, 2007 due principally to higher refined product sales prices and an increase in volumes of produced refined products sold. The average sales price we received per produced barrel sold increased 12% from $80.21 for the year ended December 31, 2006 to $89.77 for

the year ended December 31, 2007. The total volume of produced refined products sold increased 9% for the year ended December 31, 2007 compared to the same period in 2006 due principally to an increase in production following a combined 10,000 BPSD capacity expansion at our Navajo Refinery during 2006 and 2007. Additionally, sales and other revenues for the year ended December 31, 2007 include $23.0 million in sulfur credit sales compared to $15.9 million for the year ended December 31, 2006.

Cost of Products Sold

Cost of products sold increased 20% from $3,349.4 million in 2006 to $4,003.5 million in 2007 due principally to the higher costs of purchased crude oil and an increase in volumes of produced refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 13% from $64.43 in 2006 to $73.03 in 2007.

We recognized a $0.8 million charge to cost of products sold during 2007 resulting from liquidations of certain LIFO inventory quantities that were carried at higher costs as compared to current costs. In 2006, we recognized a $4.2 million reduction to cost of products sold as liquidated LIFO inventory quantities were carried at lower costs as compared to then current costs.

Refinery Gross Margin

Refining gross margin per produced barrel increased 6% from $15.78 in 2006 to $16.74 in 2007. Refinery gross margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.

Operating Expenses

Operating expenses, exclusive of depreciation and amortization increased less than 1% from $208.5 million in 2006 to $209.3 million in 2007.

General and Administrative Expenses

General and administrative expenses increased 9% from $63.3 million in 2006 to $68.8 million in 2007 due principally to increased equity-based incentive compensation expense and software implementation costs.

Depreciation and Amortization Expenses

Depreciation and amortization increased 9% from $39.7 million in 2006 to $43.5 million in 2007 due to capitalized refinery improvement projects in 2006 and 2007.

Equity in Earnings of HEP

Our equity in earnings of HEP was $19.1 million for the year ended December 31, 2007 compared to $12.9 million for the year ended December 31, 2006. The increase in our equity in earnings of HEP was due principally to an increase in HEP’s earnings for the year ended December 31, 2007 compared to the year ended December 31, 2006.

Interest Income

Interest income for the year ended December 31, 2007 was $15.1 million compared to $9.8 million for the year ended December 31, 2006. The increase in interest income was due principally to the effects of a higher interest rate environment combined with increased investments in marketable debt securities.

Interest Expense

Interest expense was $1.1 million for each of the years ended December 31, 2007 and 2006.

Income Taxes

Income taxes increased 21% from $136.6 million in 2006 to $165.3 million in 2007 due to higher pre-tax earnings in 2007 compared to 2006, partially offset by a lower effective tax rate. The effective tax rate for the year ended December 31, 2007 was 33.1% compared to 35.6% for the year ended December 31, 2006. The decrease in our effective tax rate was due principally to a statutory increase from 3% to 6% in the federal tax deduction for domestic manufacturing activities.

Discontinued Operations

We had no income from discontinued operations for the year ended December 31, 2007, as our Montana Refinery operations have ceased. Income from discontinued operations was $19.7 million for the year ended December 31, 2006 which consisted of a $14.0 million gain on the sale of the Montana Refinery, net of $8.3 million in income taxes, and $5.7 million of earnings which was largely due to the liquidation of certain retained quantities of inventories that were not included in the sale of our Montana Refinery on March 31, 2006.

LIQUIDITY AND CAPITAL RESOURCES

We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value, and are invested primarily in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings. We also invest available cash in highly-rated marketable debt securities primarily issued by government entities that have maturities greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly and may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of December 31, 2008, we had cash and cash equivalents of $40.8 million, marketable securities with maturities under one year of $49.2 million and marketable securities with maturities greater than one year, but less than two years, of $6.0 million.

Cash and cash equivalents decreased by $53.6 million during 2008. The combined cash used for investing and financing activities of $57.8 million and $151.3 million, respectively, exceeded cash provided by operating activities of $155.5 million. Working capital decreased by $148.1 million during 2008. This decrease was due principally to a reduction in cash, cash equivalents and short-term investments in marketable securities resulting from increased capital expenditures and miscellaneous year-over-year changes in collections and payments.

In March 2008, we entered into an amended and restated $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America as administrative agent and lender. The Credit Agreement has a term of five years and an option to increase the facility to $300.0 million subject to certain conditions. This credit facility expires in 2013 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2008. At December 31, 2008, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.5 million at December 31, 2008.

There are currently a total of nine lenders under our $175.0 million Credit Agreement with individual commitments ranging from $15.0 million to $27.5 million. If any particular lender could not honor its commitment, we believe the unused capacity under our Credit Agreement, which is $172.5 million as of December 31, 2008, would be available to meet our borrowing needs. Additionally, we have reviewed publicly available information on our lenders in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We have not experienced, nor do we expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

HEP has a $300.0 million senior secured revolving credit agreement (the “HEP Credit Agreement”) with Union Bank of California, N.A. as one of the lenders and as administrative agent and an option to increase the facility to $370.0 million subject to certain conditions. The HEP Credit Agreement expires in August 2011 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general partnership purposes. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included in our Consolidated Balance Sheets at December 31, 2008 consist of $5.3 million in cash and cash equivalents, $5.1 million in trade accounts receivable and other current assets, $354.1 million in property, plant and

equipment, net and $56.1 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement.

There are currently a total of thirteen lenders under the HEP Credit Agreement with individual commitments ranging from $15.0 million to $40.0 million. If any particular lender could not honor its commitment, HEP has unused capacity available under their credit agreement, which was $100.0 million as of December 31, 2008, to meet their borrowing needs. Additionally, publicly available information on these lenders is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the credit agreement. HEP has not experienced, nor do they expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, HEP believes there would be alternative lenders or options available.

The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service on up to $35.0 million of the principal amount of the HEP Senior Notes.

At December 31, 2008, the carrying amount of HEP’s long-term debt was as follows:

		(In thousands)
HEP Credit Agreement		$	200,000
HEP Senior Notes
Principal			185,000
Unamortized discount			(16,223	)
Unamortized premium — de-designated fair value hedge			2,137
			170,914
Total debt			370,914
Less short-term borrowings under HEP Credit Agreement			29,000
Total long-term debt		$	341,914

See “Risk Management” for a discussion of HEP’s interest rate swaps.

Under our common stock repurchase program, repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million or an average of $42.48 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.

We believe our current cash, cash equivalents and marketable securities, along with future internally generated cash flow and funds available under our credit facilities provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends and distributions by HEP to its minority interest holders. In addition, components of our growth strategy

may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

Cash Flows — Operating Activities

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Net cash flows provided by operating activities were $155.5 million for the year ended December 31, 2008 compared to $422.7 million for the year ended December 31, 2007, a decrease of $267.2 million. Net income for 2008 was $120.6 million, a decrease of $213.5 million from $334.1 million for 2007. Additionally, the non-cash items of depreciation and amortization, deferred taxes, equity-based compensation, gain on the sale of HPI and non-cash interest resulting from changes in the fair value of two of HEP’s interest rate swaps, resulted in an increase to operating cash flows of $104.2 million for the year ended December 31, 2008 compared to $76.5 million for the year ended December 31, 2007. Distributions in excess of equity in earnings of HEP decreased to $3.1 million for the year ended December 31, 2008 compared to $3.7 million for the year ended December 31, 2007. Working capital items decreased cash flows by $37.0 million in 2008 compared to an increase of $15.0 million in 2007. For the year ended December 31, 2008, inventories decreased by $15.0 million compared to an increase of $11.0 million for 2007. Also for 2008, accounts receivable decreased by $332.0 million compared to an increase of $216.3 million for 2007 and accounts payable decreased by $393.2 million compared to an increase of $264.2 million for 2007. Additionally, for 2008, turnaround expenditures were $34.8 million compared to $2.7 million for 2007.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Net cash flows provided by operating activities were $422.7 million for 2007 compared to $245.2 million for 2006, an increase of $177.5 million. Net income in 2007 was $334.1 million, an increase of $67.5 million from net income of $266.6 million for 2006. The non-cash items of depreciation and amortization, deferred taxes, equity-based compensation and gain on sale of assets resulted in an increase to operating cash flows of $76.5 million for the year ended December 31, 2007 compared to $31.4 million for the year ended December 31, 2006. Distributions in excess of equity in earnings of HEP decreased to $3.7 million for the year ended December 31, 2007 compared to $7.4 million for the year ended December 31, 2006. Working capital items increased cash flows by $15.0 million in 2007 compared to a decrease of $40.9 million in 2006. For the year ended December 31, 2007, inventories increased by $11.0 million compared to an increase of $33.8 million for the year ended December 31, 2006. Also for 2007, accounts receivable increased by $216.3 million compared to a decrease of $12.1 million for 2006 and accounts payable increased by $264.2 million compared to a decrease of $26.4 million for 2006. Additionally, for 2007, turnaround expenditures were $2.7 million compared to $11.6 million for 2006.

Cash Flows — Investing Activities and Planned Capital Expenditures

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Net cash flows used for investing activities were $57.8 million for 2008 compared to $293.1 million for 2007, a decrease of $235.3 million. Cash expenditures for property, plant and equipment for 2008 totaled $418.1 million compared to $161.3 million for 2007. Capital expenditures for the year ended December 31, 2008 include $34.3 million attributable to HEP. Also, in 2008 we invested $769.1 million in marketable securities and received proceeds of $945.5 million from the sales and maturities of marketable securities. Additionally for the year ended December 31, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP on February 29, 2008. We are also presenting HEP’s March 1, 2008 cash balance of $7.3 million as an inflow as a result of our reconsolidation of HEP effective March 1, 2008. For the year ended December 31, 2007, we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities of marketable securities.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Net cash flows used for investing activities were $293.1 million for 2007 compared to net cash flows provided by investing activities of $35.8 million for 2006, a decrease of $328.9 million. Cash expenditures for property, plant and equipment for 2007 totaled $161.3 million compared to $120.4 million for 2006. Also, in 2007 we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities of marketable securities. For the year ended December 31, 2006, we invested $212.0 million in marketable securities and received proceeds of $319.3 million from sales and maturities of marketable securities. Furthermore in 2006, we received cash proceeds of $48.9 million following the sale of our Montana Refinery on March 31, 2006.

Planned Capital Expenditures

Holly Corporation

Each year our Board of Directors approves in our annual capital budget capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total new capital budget for 2009 is approximately $19.8 million, not including the capital projects approved in prior years, and our expansion and feedstock flexibility projects at the Navajo and Woods Cross refineries, as described below. The 2009 capital budget is comprised of $11.4 million for refining improvement projects for the Navajo Refinery, $5.3 million for projects at the Woods Cross Refinery, $0.4 million for marketing-related projects, $1.4 million for asphalt plant projects and $1.3 million for other miscellaneous projects.

At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum units. Phase I is expected to be mechanically complete in the first quarter of 2009 and was originally estimated to cost $163.0 million. The total cost of phase I is now expected to be approximately $185.0 million. The added costs are associated with permit timing delays, scope changes due to permit required pollution control equipment that was not anticipated, material cost escalation and increased labor rates.

Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 and was originally estimated to cost $84.0 million. The total cost of phase II is now expected to be approximately $96.0 million. The added costs are associated with better scope definition on the Artesia crude and vacuum unit revamp portion of the overall project and material cost escalation.

We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $15.0 million and are expected to be completed at the same time as the phase II project.

The Navajo Refinery is also installing a new 100 ton per day sulfur recovery unit that is scheduled for mechanical completion early in the first quarter of 2009. The project was originally estimated to cost $26.0 million and is now projected to cost $31.0 million. The added costs are associated permit delays, material cost escalation and increased labor rates.

Once the Navajo projects discussed above are complete, the Navajo Refinery will be able to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt with all their performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks and enable the refinery to meet new LSG specifications required by the EPA.

At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipment and black wax unloading systems. The total cost of this project was approximately $122.0 million versus our original $105.0 million estimate. Increased costs resulted from offsite scope additions, material cost escalation and increased labor rates. The projects were completed in the fourth quarter of 2008. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.

To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. HEP’s joint venture pipeline with Plains will permit the transportation of additional crude oil into the Salt Lake City area. HEP’s joint venture project with Plains is further described under the HEP section of this discussion of planned capital expenditures.

In December 2007, we entered into a definitive agreement with Sinclair to jointly build 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 and Sinclair owns the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million, with our share of the cost totaling $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered into 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. Additionally in 2008, we purchased a terminal and rail facility located near Cedar City, Utah that will serve as a key component of our UNEV joint venture pipeline.

The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.

In July 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion’s pipeline from Cushing, Oklahoma to its Slaughter Station located in west Texas. Our Board of Directors has approved capital expenditures of up to $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico and a 65-mile pipeline from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline project that connects HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. Under the provisions of the Omnibus Agreement with HEP, HEP will have an option to purchase these transportation assets upon our completion of these projects. We expect to complete these projects in the fourth quarter of 2009.

In 2009, we expect to spend approximately $350.0 million on currently approved capital projects, including sustaining capital and turnaround costs. This amount consists of certain carryovers of capital projects from previous years, less carryovers to subsequent years of certain of the currently approved capital projects.

In October 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act provided an immediate deduction of 75% of certain costs paid or incurred to comply with the ULSD standards, and a tax credit based on ULSD production of up to 25% of those costs. In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act created tax incentives for refiners by providing for an immediate deduction of 50% of certain refinery capacity expansion costs when the expansion assets are placed in service. We believe the capacity expansion projects at the Navajo and Woods Cross Refineries qualify for this deduction.

The above mentioned regulatory compliance items, including the ULSD and LSG requirements, or other presently existing or future environmental regulations could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements.

HEP

Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in their current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2009 HEP capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of the South System and the joint venture with Plains discussed below.

In October 2007, we amended the HEP PTA under which HEP has agreed to expand their South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at HEP’s El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. HEP expects to complete the majority of this project in early 2009.

In November 2007, HEP executed a definitive agreement with Plains to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by HEP. HEP expects to purchase their 25% interest in the joint venture in March 2009 when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including our Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah that is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of HEP’s investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to us upon the closing of their investment in the SLC Pipeline.

HEP is currently working on a capital improvement project that will provide increased flexibility and capacity to their intermediate pipelines enabling them to accommodate increased volumes following the completion of our Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $5.1 million.

Also, HEP is currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline at an estimated cost of $1.9 million for completion in early 2009.

Cash Flows — Financing Activities

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Net cash flows used for financing activities were $151.3 million for 2008 compared to $189.4 million for 2007, a decrease of $38.1 million. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29.0 million under the HEP Credit Agreement and purchased $0.8 million in HEP common units in the open market for restricted unit grants. Additionally in 2008, we paid an aggregate of $0.9 million in deferred financing costs related to our amended and restated Credit Agreement and the HEP Credit Agreement. Under our common stock repurchase program, we purchased treasury stock of $151.1 million in 2008. We also paid $29.1 million in dividends, received a $17.0 million contribution from our UNEV Pipeline joint venture partner, received $1.0 million for common stock issued upon exercise of stock options and recognized $5.7 million in excess tax benefits on our equity based compensation during 2008. Also during this period, HEP paid $22.1 million in distributions to its minority interest holders. During 2007, we purchased treasury stock of $207.2 million under our

stock repurchase program, paid $23.2 million in dividends, received $2.3 million for common stock issued upon exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Net cash flows used for financing activities were $189.4 million for 2007 compared to $175.9 million for 2006, an increase of $13.5 million. Under our common stock repurchase program, we purchased treasury stock of $207.2 million in 2007. We also paid $23.2 million in dividends, received $2.3 million for common stock issued upon exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation during 2007. During 2006, we purchased treasury stock of $175.4 million under our stock repurchase program, paid $15.0 million in dividends, received $2.6 million for common stock issued upon exercise of stock options and recognized $11.8 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2008 in total and by period due beginning in 2009. Effective March 1, 2008, we reconsolidated HEP. As a result, the table below does not include our contractual obligations to HEP under our three long-term transportation agreements with HEP. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2. “Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.

						Payments Due by Period
						Less than												Over
Contractual Obligations(3)(4)		Total				1 Year				2-3 Years				4-5 Years				5 Years
		(In thousands)
Holly Corporation
Operating leases		$	6,062			$	2,461			$	3,327			$	190			$	84
Hydrogen supply agreement(1)			91,570				6,315				12,630				12,630				59,995
Other service agreements(2)			13,953				2,371				3,970				3,857				3,755
			111,585				11,147				19,927				16,677				63,834
Holly Energy Partners
Long-term debt — principal(5)			356,000				—				171,000				—				185,000
Long-term debt — interest(6)			85,240				15,344				29,427				23,125				17,344
Pipeline operating and right of way leases			54,473				6,364				12,709				12,645				22,755
Other agreements			23,049				5,221				5,178				4,600				8,050
			518,762				26,929				218,314				40,370				233,149
Total		$	630,347			$	38,076			$	238,241			$	57,047			$	296,983