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, 2007

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 (Do not check if a smaller reporting company)		Smaller Reporting Company o

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, 2007 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $3,020,000. (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.)

50,983,492 shares of Common Stock, par value $.01 per share, were outstanding on February 7, 2008.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 8, 2008, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2007, are incorporated by reference in Part III.

 

 

TABLE OF CONTENTS

Item		Page
PART I
Forward-Looking Statements			3
Definitions			4
1 and 2. Business and properties			7
1A. Risk factors			21
1B. Unresolved staff comments			26
3. Legal proceedings			26
4. Submission of matters to a vote of security holders			27
PART II
5. Market for the Registrant’s common equity, related stockholder matters and issuer purchases of equity securities			28
6. Selected financial data			29
7. Management’s discussion and analysis of financial condition and results of operations			30
7A. Quantitative and qualitative disclosures about market risk			48
Reconciliations to amounts reported under generally accepted accounting principles			48
8. Financial statements and supplementary data			54
9. Changes in and disagreements with accountants on accounting and financial disclosure			86
9A. Controls and procedures			86
9B. Other information			86
PART III
10. Directors, executive officers and corporate governance			86
11. Executive compensation			86
12. Security ownership of certain beneficial owners and management and related stockholder matters			87
13. Certain relationships, related transactions and director independence			87
14. Principal accountant fees and services			87
PART IV
15. Exhibits and financial statement schedules			88
Signatures			89
Index to exhibits			91
Subsidiares of the Registrant
Consent of Independent Registered Public Accounting Firm
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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 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. 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.

     “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, depletion 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
CAA			19
CERCLA			20
Connacher			8
Consent Agreement			19
CWA			20
DESC			13
EBITDA			32
EPA			13
Exchange Act			86
FASB			7
FERC			26
FIN 46			7
HEP			7
HEP IPA			17
HEP PTA			17
HEP Senior Notes			38
Leased Pipeline			7
LIFO			34
MDEQ			27
Montana Refinery			8
MRC			27
Navajo Refinery			7
NPDES			20
PEMEX			9
Plains			11
Rio Grande			7
SEC			7
SDWA			20
SFAS			44
SFPP			11
VIE			44
VRDN			37
Woods Cross Refinery			7

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.

We are principally an independent petroleum refiner which 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 web site 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. On April 26, 2004, our stock began trading on the New York Stock Exchange under the trading symbol “HOC”. Our stock formerly traded on the American Stock Exchange.

In July 2004, we completed the initial public offering of limited partnership interests in Holly Energy Partners, L.P. (“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”). We initially consolidated the results of HEP and showed the interest we did not own as a minority interest in ownership and earnings. On July 8, 2005, we closed on a transaction for HEP to acquire our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities, which reduced our ownership interest in HEP to 45.0%. Under the provision of the Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised), “Consolidation of Variable Interest Entities,” (“FIN 46”) we deconsolidated HEP effective July 1, 2005. The deconsolidation has been presented from July 1, 2005 forward, and our share of the earnings of HEP from July 1, 2005 is reported using the equity method of accounting.

As of December 31, 2007, 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 approximately 900 miles of crude oil pipelines located principally in west Texas and New Mexico;
	•		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 45% interest in HEP (which includes our 2% general partnership interest), which has logistics assets including approximately 1,700 miles of petroleum product pipelines located in Texas, New Mexico and Oklahoma (including 340 miles of leased pipeline); ten refined product terminals; two refinery truck rack facilities; a refined products tank farm facility; and a 70% interest in Rio Grande.

On February 26, 2008, we announced an agreement for the sale of certain pipeline and tankage assets to HEP for $180.0 million. The agreement provides for consideration to us of $171.0 million in cash and HEP common units valued at approximately $9.0 million. The assets include 136 miles of crude oil trunk lines that deliver crude to our Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000

barrels of storage capacity located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support our Woods Cross Refinery. In connection with the closing of this transaction, we will enter into a 15-year pipelines and tankage agreement with HEP that will contain a minimum annual revenue commitment to HEP from us. This transaction is expected to close on February 29, 2008. We expect the consummation of this proposed transaction to result in our owning a beneficial variable interest in HEP in excess of 50%. In accordance with provisions under FIN 46, we expect to reconsolidate HEP effective March 1, 2008.

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 of sour and sweet crude oils, can process up to approximately 90% sour crude oils, 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 26,000 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. In conjunction with the refining operations, we own approximately 900 miles of crude oil pipelines that serve primarily as the supply network for our New Mexico refinery operations that we have agreed to sell to HEP as discussed above.

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 one business segment, Refining. The Refining business segment includes the Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. Prior to our deconsolidation of HEP on July 1, 2005 our operations were organized into two business segments, which were Refining and HEP. Our operations that are not included in either the Refining or HEP (prior to its deconsolidation) business segments include the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program, and prior to the deconsolidation of HEP, the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us as well as the recognition of the minority interests’ income of HEP.

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, depletion 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 under this section of “Refinery Operations.”

		Years Ended December 31,
		2007				2006				2005
Consolidated (7)
Crude charge (BPD) (1)			103,490				96,570				95,950
Refinery production (BPD) (2)			113,270				105,730				106,040
Sales of produced refined products (BPD)			115,050				105,090				106,500
Sales of refined products (BPD) (3)			126,800				119,870				117,110
Refinery utilization (4)			94.1	%			92.4	%			95.0	%
Average per produced barrel (5)
Net sales		$	89.77			$	80.21			$	69.12
Cost of products			73.03				64.43				56.50
Refinery gross margin			16.74				15.78				12.62
Refinery operating expenses (6)			4.43				4.83				4.11
Net operating margin		$	12.31			$	10.95			$	8.51

		Years Ended December 31,
		2007				2006				2005
Feedstocks:
Sour crude oil			62	%			61	%			67	%
Sweet crude oil			26	%			28	%			21	%
Other feedstocks and blends			12	%			11	%			12	%
Total			100	%			100	%			100	%

The petroleum refining business is highly competitive. Among our competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. We also compete with other independent refiners. Competition in a particular geographic area is affected primarily by the amount of refined products produced by refineries located in that area and by the availability of refined products and the cost of transportation to that area from refineries located outside the area. Projects have been explored from time to time by refiners and other entities which projects, if completed, could result in further increases in the supply of products to some or all of our markets. In recent years, there have been several refining and marketing consolidations or acquisitions between competitors in our geographic markets. These transactions could increase future competitive pressures on us.

Set forth below is information regarding our principal products.

		Years Ended December 31,
		2007				2006				2005
Consolidated
Sales of produced refined products:
Gasolines			60	%			61	%			59	%
Diesel fuels			29	%			28	%			27	%
Jet fuels			2	%			3	%			4	%
Fuel oil			4	%			3	%			2	%
Asphalt			2	%			2	%			4	%
LPG and other			3	%			3	%			4	%
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, an affiliate of Petróleos Mexicanos (“PEMEX”), the government-owned energy company of Mexico, 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. Loss of, or reduction in amounts purchased by, our major customers that purchase for their retail operations 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.

In order to maintain or increase production levels at our refineries, we must continually enter into contracts for new crude oil supplies. The primary factors affecting our ability to contract for new crude oil supplies are our ability to connect new supplies of crude oil to our gathering systems or to our other crude oil receiving lines, our success in

contracting for and receiving existing crude oil supplies that are currently being purchased by other refineries and the level of drilling activity near our gathering systems or our other crude oil receiving lines.

Navajo Refinery

Facilities

The Navajo Refinery has a 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 92% of its raw materials throughput into high value light products. For 2007, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 59%, 30% and 3%, respectively, of the Navajo Refinery’s sales volumes.

The following table sets forth information about the Navajo Refinery operations, including non-GAAP performance measures. The cost of products and refinery gross margin do not include the effect of depreciation, depletion 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,
		2007				2006				2005
Navajo Refinery
Crude Charge (BPD) (1)			79,460				72,930				71,850
Refinery production (BPD) (2)			87,930				80,540				80,190
Sales of produced refined products (BPD)			88,920				79,940				80,110
Sales of refined products (BPD) (3)			100,460				93,660				89,400
Refinery utilization (4)			94.6	%			92.9	%			95.8	%
Average per produced barrel (5)
Net sales		$	89.68			$	79.62			$	69.11
Cost of products			74.10				64.25				55.50
Refinery gross margin			15.58				15.37				13.61
Refinery operating expenses (6)			4.30				4.74				3.94
Net operating margin		$	11.28			$	10.63			$	9.67
Feedstocks:
Sour crude oil			82	%			80	%			85	%
Sweet crude oil			9	%			8	%			2	%
Other feedstocks and blends			9	%			12	%			13	%
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, 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 and associated vacuum distillation units which were originally constructed after 1970. The facility also has an additional 1.1 million barrels of feedstock and product tankage. The Lovington facility processes crude oil into intermediate products, which are transported to Artesia by means of two intermediate pipelines owned by HEP and which are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the two facilities is 85,000 BPSD and typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.

We have approximately 900 miles of crude gathering pipelines transporting crude oil to the Artesia and Lovington facilities from various points in southeastern New Mexico and west Texas, 67 crude oil trucks and 67 trailers in addition to over 600,000 barrels of related tankage.

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, ConocoPhillips, 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 47,000 BPD of refined products into the Arizona market, comprised primarily of Phoenix and Tucson, which accounts for approximately 16% of the refined products consumed in that market.

We use Kinder Morgan’s SFPP pipeline to serve the Arizona market. In December 2007, Kinder Morgan completed an expansion of its El Paso, Texas to Tucson and Phoenix, Arizona pipeline, increasing its capacity to approximately 200,000 BPD. Although we expect that we and other refiners will ship additional volumes of refined product via this pipeline, we cannot presently predict the ultimate effects on us.

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 ConocoPhillips. We currently supply approximately 21,000 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 “Leased Pipeline”). 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 Leased Pipeline’s capabilities.

The Longhorn Pipeline is a 72,000 BPD common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. Deliveries of refined products shipped on the Longhorn Pipeline increased significantly during 2007, and we believe the Longhorn Pipeline is currently operating at near full capacity. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has also announced a planned expansion of its pipeline throughput capacity from 72,000 BPD to 125,000 BPD.

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 which 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 our pipelines and 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 2007, approximately 4,500 BPD of isobutane and 4,100 BPD of natural gasoline used in the Navajo Refinery’s operations were purchased from a newly operational fractionation facility in Hobbs, New Mexico, that 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,
		2007				2006				2005
Navajo Refinery
Sales of produced refined products:
Gasolines			59	%			60	%			59	%
Diesel fuels			30	%			28	%			27	%
Jet fuels			3	%			4	%			4	%
Fuel oil			3	%			2	%			—	%
Asphalt			2	%			3	%			6	%
LPG and other			3	%			3	%			4	%
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, an affiliate of PEMEX 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 800 BPD of jet fuel to the DESC in 2007. We have had a military jet fuel supply contract with the United States Government for each of the last 38 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 2007, the DESC awarded us contracts for sales of military jet fuel for the period from October 1, 2007 through September 30, 2008. Our total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, is approximately 22 million gallons as compared to the total award for the 2006-2007 contract year of approximately 52 million gallons. The loss of or further reduction of quantities of jet fuel provided under our military jet fuel contract with the United States Government could have an adverse effect on our results of operations if alternate commercial jet fuel or additional diesel fuel sales could not be secured.

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 2008 of $21.0 million for refining improvement projects for the Navajo Refinery, not including the capital projects approved in prior years or our expansion and feedstock flexibility projects described below.

As announced in December 2006 we will be installing a new 15,000 BPD hydrocracker and a new 28 MMSCFD hydrogen plant at a budgeted cost of approximately $125.0 million. The addition of these units is expected to increase liquid volume recovery, increase the refinery’s capacity to process outside feedstocks, and increase yields of high valued products, as well as enabling the refinery to meet new low sulfur gasoline specifications required by the Environmental Protection Agency (“EPA”). The hydrocracker and hydrogen plant projects will provide improved heavy crude oil processing flexibility.

As announced in February 2007, we are revamping an existing crude unit which will increase the crude capacity at the Navajo Refinery to approximately 100,000 BPD. Additionally, our Board of Directors has approved a revamp of its second crude unit and a new solvent de-asphalter unit. The approved components, combined with the above described components approved in 2006, bring the total budgeted amount for this expansion and heavy crude oil processing project to $245.0 million. It is currently anticipated that the expansion portion of the overall project consisting of the initial crude unit revamp, the new hydrocracker and the new hydrogen plant will be completed and operational by the first quarter of 2009. The completion of the heavy crude oil processing portion of the overall project, including the second crude unit revamp and the installation of the new solvent de-asphalter, will be targeted to coincide with the development of future pipeline access to the Navajo Refinery for heavy Canadian crude oil and other foreign heavy crude oils transported from the Cushing, Oklahoma area. We plan to explore with HEP the most economical manner to obtain this needed pipeline access.

Also at the Navajo Refinery, a project to install an additional 100 ton per day sulfur recovery unit included in the 2006 capital budget is currently underway at an estimated cost of $26.0 million, of which we have spent approximately $10.0 million to date. This new sulfur recovery unit will permit our Navajo Refinery to process 100% sour crude and is planned for start-up in the third quarter of 2008. It is anticipated that the projects that will

be completed by the fourth quarter of 2008 will also enable the Navajo Refinery, without significant additional investment, to comply with LSG specifications required by the end of 2010.

Woods Cross Refinery

Facilities

The Woods Cross Refinery has a crude oil capacity of 26,000 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 2007, gasoline, diesel and jet fuel (excluding volumes purchased for resale) represented 63%, 27% and 2%, 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, depletion 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,
		2007				2006				2005
Woods Cross Refinery
Crude Charge (BPD) (1)			24,030				23,640				24,100
Refinery production (BPD) (2)			25,340				25,190				25,850
Sales of produced refined products (BPD)			26,130				25,150				26,390
Sales of refined products (BPD) (3)			26,340				26,210				27,710
Refinery utilization (4)			92.4	%			90.9	%			92.7	%
Average per produced barrel (5)
Net sales		$	90.09			$	82.09			$	69.13
Cost of products			69.40				64.99				59.51
Refinery gross margin			20.69				17.10				9.62
Refinery operating expenses (6)			4.86				5.13				4.61
Net operating margin		$	15.83			$	11.97			$	5.01
Feedstocks:
Sour crude oil			3	%			2	%			8	%
Sweet crude oil			89	%			89	%			82	%
Other feedstocks and blends			8	%			9	%			10	%
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, maintenance shops, warehouses and office buildings. The operating units at the Woods Cross facility 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 facility is 26,000 BPSD and the facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane, and gas oil.

We operate 14 miles of crude, refined products and hydrogen pipelines that allow us to connect our Woods Cross Refinery to common carrier pipeline systems and to a hydrogen plant located at Chevron’s Salt Lake City Refinery.

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 146,000 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 Pioneer Pipeline”). The Woods Cross Refinery’s primary markets include Utah, Idaho, Nevada and Wyoming. Approximately 60% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillip 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 18,000 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 7,500 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 which 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,
		2007				2006				2005
Woods Cross Refinery
Sales of produced refined products:
Gasolines			63	%			63	%			60	%
Diesel fuels			27	%			28	%			29	%
Jet fuels			2	%			2	%			2	%
Fuel oil			5	%			5	%			7	%
Asphalt			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. Jet fuel is sold for military and 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.

Military jet fuel is sold to the DESC under a series of one-year contracts that can vary significantly from year to year. We sold approximately 100 BPD of jet fuel to the DESC in 2007. 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. We did not obtain a contract with the DESC for the October 1, 2007 through September 30, 2008 period. Our total contract award for the 2006-2007 contract year was approximately 8 million gallons.

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, which originate in Canada, Wyoming and Colorado. Supplies of black wax crude oil are shipped via truck.

Capital Improvement Projects

Our approved capital budget for 2008 capital projects at the Woods Cross Refinery is $7.7 million not including the major projects described below or other capital projects approved in prior years. As announced in December 2006, we will be adding a new 15,000 BPD hydrocracker along with sulfur recovery and desalting equipment at our Woods Cross Refinery. The budgeted cost of these additions is approximately $105.0 million. These additions will expand the Woods Cross Refinery’s crude processing capabilities from 26,000 BPD to 31,000 BPD while enabling the refinery to process up to 10,000 BPD of high-value low-priced black wax crude oil and up to 5,000 BPD of low-priced heavy Canadian crude oils. This expansion project as approved involves a higher capital investment than had originally been estimated, principally because of the substitution of a complex hydrocracker in place of certain desulfurization and expanded bottoms-processing modifications that had been included in preliminary planning. The substitution of the complex hydrocracker is expected to provide increased capabilities to process significantly more black wax crude oils, which have recently been priced at substantial discounts to West Texas Intermediate crude oil while yielding substantially higher value products than the discounted heavy Canadian crudes that were a more significant part of the original plan. These additions would also increase the refinery’s capacity to process low-cost feedstocks and provide the necessary infrastructure for future expansions of crude oil refining capacity at the Woods Cross Refinery. The approved projects for the Woods Cross refinery are expected to be completed during the fourth quarter of 2008.

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. In November 2007, HEP entered into an

agreement with Plains All American Pipeline, L.P. (“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”). 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, which is currently flowing on Plains’ Rocky Mountain Pipeline. The project is currently expected to be fully operational by the second quarter of 2008.

In December 2007, we entered into a definitive agreement with Sinclair Transportation Company (“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 will own 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. Holly’s share of this cost is $225.0 million. Construction of this project is currently expected to be completed and operational in mid 2009. 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 our equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum.

HOLLY ENERGY PARTNERS, L.P.

In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that also trades on the New York Stock Exchange under the trading symbol “HEP”. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande. On February 28, 2005, HEP closed on a contribution agreement with Alon and several of its wholly-owned subsidiaries that provided for HEP’s acquisition of four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas. On July 8, 2005, we closed on a transaction for HEP to acquire our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities, a transaction which diluted our ownership interest in HEP to 45.0%. We initially consolidated the results of HEP and showed the interest we did not own as a minority interest in ownership and earnings. Under the provisions of FIN 46, we have deconsolidated HEP effective July 1, 2005. From July 1, 2005 forward, our share of the earnings of HEP is reported using the equity method of accounting. For additional information about the formation of HEP and the subsequent Alon and intermediate pipelines transactions, see Note 3 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”

HEP operates a system of petroleum pipelines and distribution terminals in Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. HEP generates revenues by charging tariffs for transporting petroleum products 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 does not take ownership of products that it transports or terminals except for terminal overages prior to October 1, 2007; therefore, it is not directly exposed to changes in commodity prices. HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring 2019 and the 15-year intermediate pipelines agreement expiring 2020 (“HEP IPA”). The agreements provide that we transport or terminal volumes on certain of HEP’s facilities that will result in minimum annual payments to HEP, currently $39.6 million under the HEP PTA and $12.8 million under the HEP IPA. In addition, we have agreed to indemnify HEP, subject to certain limits, for any historical environmental noncompliance and remediation liabilities. The substantial majority of HEP’s business is devoted to providing transportation and terminalling services to us.

In October 2007, we entered into an agreement that amends the HEP PTA under which HEP has agreed to expand their pipeline system between Artesia, New Mexico and El Paso, Texas (“South System”). The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at their El Paso terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. Currently, this project is expected to be

completed by January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008, on our shipments on HEP’s refined product pipelines.

As of December 31, 2007, HEP’s assets include:

     Pipelines:

	•		approximately 780 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; 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:

	•		four refined product terminals (one of which is 50% owned), located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1.1 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; and
	•		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.

On February 26, 2008, we announced an agreement for the sale of certain pipeline and tankage assets to HEP for $180.0 million. The agreement provides for consideration to us of $171.0 million in cash and HEP common units valued at approximately $9.0 million. The assets include 136 miles of crude oil trunk lines that deliver crude to our Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000 barrels of storage capacity located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support our Woods Cross Refinery. In connection with the closing of this transaction, we will enter into a 15-year pipelines and tankage agreement with HEP that will contain a minimum annual revenue commitment to HEP from us. This transaction is expected to close on February 29, 2008. We expect the consummation of this proposed transaction to result in our owning a beneficial variable interest in HEP in excess of 50%. In accordance with provisions under FIN 46, we expect to reconsolidate HEP effective March 1, 2008.

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 $109,000 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

We conduct a small-scale oil and gas exploration and production program. We have not budgeted any significant amounts for these activities in 2008.

Employees and Labor Relations

As of December 31, 2007, we had 909 employees, of which 282 are covered by collective bargaining agreements that expire during 2009 and 2010. We consider our employee relations to be good.

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 December 2001, we entered into an agreement for a Consent Decree (“Consent Agreement”) with the EPA and the New Mexico Environment Department of Environmental Quality with respect to a global settlement of issues concerning the application of air quality requirements to past and future operations of our Navajo Refinery. The Consent Agreement requires us to make investments at our Navajo Refinery for the installation of certain state of the art pollution control equipment expected to total approximately $14.0 million. With the investments made to date, our outstanding required investment is no longer significant.

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 proposed agreement, which has not yet been signed by the parties and lodged with the federal district court in Utah, includes obligations for us to make specified additional capital investments currently estimated to total approximately $17 million over several years and to make changes in operating procedures at the refinery. The proposed agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit of 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 December 1999, the EPA promulgated national regulations limiting the amount of sulfur allowable in gasoline. The new regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those western states exhibiting lesser air quality problems. Subsequently, the EPA promulgated regulations further limiting the sulfur content of highway fuel to 15 PPM. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel.

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. 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, both of our refineries met the ultimate 15 PPM standard for both our non-road and highway diesel fuel by June 1, 2006, the earliest deadline for large refiners. This entailed substantial capital expenditures; however, these capital expenditures would have been required later. Our early compliance with this initiative enabled us to obtain additional small refiner extensions on the low sulfur gasoline requirements.

We are currently reviewing new EPA regulations on gasoline that would 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 liabilities 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 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.

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, by competition in the particular geographic areas that we serve and by 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.

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.

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. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control. These projects may not be completed on schedule or at all or at the budgeted cost. 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.

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. 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 or may not produce the results intended. 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.

We may incur significant costs to comply with new or changing environmental, 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 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.

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 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. 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.

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

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 phases of the refining industry.

We are not engaged in any significant 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.

Other refiners could expand existing facilities or build new ones in our markets and significantly affect our profitability. For example, Arizona Clean Fuels Yuma, LLC has obtained a permit to construct a 150,000 BPD refinery in Arizona and is currently seeking financing for that project.

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. 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.

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.

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. Deliveries of refined products shipped on the Longhorn Pipeline increased significantly during 2007, and we believe the Longhorn Pipeline is currently operating near full capacity. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has also announced a planned expansion of its pipeline throughput capacity from 72,000 BPD to 125,000 BPD. Also in 2007, Kinder Morgan completed an expansion of its El Paso, Texas to Tucson and Phoenix, Arizona pipeline, increasing its capacity to approximately 200,000 BPD. 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.

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 distribution network for our refined products and we own a significant equity interest in HEP.

We currently own a 45% interest in HEP, including the 2% general partner interest. HEP operates a system of refined product pipelines and distribution terminals in Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. HEP generates revenues by charging tariffs for transporting refined products 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 two 15-year pipelines and terminals agreements expiring in 2019 and 2020. The agreements provide that we transport or terminal volumes on certain of HEP’s facilities that result in revenues to HEP at least equal to specified minimum revenue amounts annually. Furthermore, through our 45% ownership of HEP, we record our share of HEP’s earnings and receive distributions from 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 adversely impacting HEP could affect our distribution system or the earnings and cash flows we receive from HEP and thereby adversely affect our results of operations and financial condition.

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, 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. 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 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 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.

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. 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.

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.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

Item 3. Legal Proceedings

On May 29, 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 Federal Energy Regulatory Commission (“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 29, 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. We currently estimate that, as a result of this 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. These discussions resulted in a partial settlement, which became final in February 2008, providing for a payment to us of approximately $1.3 million with respect to our shipments from El Paso to Tucson and Phoenix for the period from June 1, 2006 through November 30, 2007. The partial settlement leaves for resolution in pending proceedings all remaining issues for other periods.

In January 2008, we settled with a mutual release our lawsuit that had been pending in the United States Court of Federal Claims against the Department of Defense relating to claims totaling approximately $299.0 million with respect to jet fuel sales by two subsidiaries in the years 1982 through 1999. Under the terms of the settlement no amount will be paid to us or by us with respect to this lawsuit.

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 proposed agreement, which has not yet been signed by the parties and lodged with the federal district court in Utah, includes obligations for us to make specified additional capital investments currently estimated to total approximately $17 million over several years and to make changes in operating procedures at the refinery. The proposed agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit of 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.

Our Navajo Refining Company subsidiary is 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. The lawsuit, as amended in October 2006 through the filing of a second amended complaint in the U.S. District Court for the Southern District of New York under multidistrict procedures, 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 claims made are for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy. The second amended complaint also contains a claim, which is asserted in the complaint only against certain other defendants but which appears to be similar to a claim that has been threatened in a mailing to Navajo by law firms representing the plaintiff in this case, alleging violations of certain provisions of the Toxic Substances Control Act. The lawsuit seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. As of the close of business on the day prior to the date of this report, Navajo has not been served in this case. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

In December 2006, the Montana Department of Environmental Quality (“MDEQ”) filed in state district court in Great Falls, Montana a Complaint and Application for Preliminary Injunction (the “Complaint”) naming as defendants Montana Refining Company (“MRC”), 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. The MDEQ asserts in the Complaint 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 Complaint sought penalties under applicable law of up to $10,000 per violation and an order enjoining MRC and the current owner of the refinery from further violations. While we do not agree with a number of the violations asserted in the Complaint, we and the current owner of the Great Falls refinery have negotiated with the MDEQ both before and after the filing of the Complaint to attempt to settle the issues raised on a compromise basis. At the date of this report, we have negotiated a tentative settlement agreement, which has not yet been put into a signed agreement, under which we would make payments totaling approximately $100,000.

We are a party to various other litigation and proceedings not mentioned in this report which we believe, based on advice of counsel, will not have 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 2007.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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 (adjusted for the two-for-one stock split effective June 1, 2006) for the periods indicated:

														Trading
Years ended December 31,		High				Low				Dividends				Volume
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
2006
First Quarter		$	37.92			$	27.93			$	0.05				47,232,600
Second Quarter		$	48.20			$	36.23			$	0.08				68,210,900
Third Quarter		$	55.96			$	38.04			$	0.08				77,970,800
Fourth Quarter		$	56.44			$	39.38			$	0.08				52,161,800

As of February 7, 2008, we had approximately 39,800 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.”

During 2007, our Board of Directors authorized a total increase of $300.0 million to our common stock repurchase program. Common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. The following table includes repurchases made under this program during the fourth quarter of 2007.

														Maximum Dollar
										Total Number of				Value of Shares Yet
										Shares Purchased				to be Purchased
										Under Approved				Under Approved
		Total Number of				Average Price Paid				Stock Repurchase				Stock Repurchase
Period		Shares Purchased				Per Share				Program				Program(1)
October 1 — October 31			—			$	—				—			$	114,005,966
November 1 — November 30			464,511			$	47.40				464,511			$	91,986,552
December 1 — December 31			2,230,684			$	49.35				2,230,684			$	181,901,475
Total			2,695,195			$	49.01				2,695,195

On February 25, 2008 our Board of Directors declared a regular quarterly cash dividend of $0.15 per share, payable April 2, 2008 to holders of record on March 19, 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,
		2007(1)				2006(1)(3)				2005(1)(2)(3)				2004(2)(3)				2003(2)(3)
		(In thousands, except per share data)
FINANCIAL DATA
For the period
Sales and other revenues		$	4,791,742			$	4,023,217			$	3,046,313			$	2,116,245			$	1,302,699
Income from continuing operations before income taxes			499,444				383,501				263,652				136,929				74,211
Income tax provision			165,316				136,603				99,626				53,985				28,250
Income from continuing operations			334,128				246,898				164,026				82,944				45,961
Income from discontinued operations, net of taxes			—				19,668				2,963				935				92
Net income before cumulative effect of change in accounting principle			334,128				266,566				166,989				83,879				46,053
Cumulative effect of accounting change (net of income tax expense of $426)			—				—				669				—				—
Net income		$	334,128			$	266,566			$	167,658			$	83,879			$	46,053
Net income per common share — basic		$	6.09			$	4.68			$	2.72			$	1.34			$	0.74
Net income per common share — diluted		$	5.98			$	4.58			$	2.65			$	1.30			$	0.72
Cash dividends declared per common share		$	0.46			$	0.29			$	0.19			$	0.145			$	0.11
Average number of common shares outstanding:
Basic			54,852				56,976				61,728				62,780				62,020
Diluted			55,850				58,210				63,244				64,340				64,064
Net cash provided by operating activities		$	422,737			$	245,183			$	251,234			$	164,604			$	75,440
Net cash provided by (used for) investing activities		$	(293,057	)		$	35,805			$	(320,135	)		$	(194,003	)		$	(122,714	)
Net cash provided by (used for) financing activities		$	(189,428	)		$	(175,935	)		$	50,505			$	85,169			$	34,698
At end of period
Cash, cash equivalents and investments in marketable securities		$	329,784			$	255,953			$	254,842			$	219,265			$	11,690
Working capital		$	216,541			$	240,181			$	210,103			$	159,839			$	(14,223	)
Total assets		$	1,663,945			$	1,237,869			$	1,142,900			$	982,713			$	706,558
Total debt, including current maturities and borrowings under credit agreements		$	—			$	—			$	—			$	33,572			$	67,142
Stockholders’ equity		$	593,794			$	466,094			$	377,351			$	339,916			$	286,609

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.

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, 2007, our refineries had a combined crude capacity of 111,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2007, we also owned a 45% 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, 2007 were $4,791.7 million and $334.1 million, respectively. Our sales and other revenues and net income for the year ended December 31, 2006 were $4,023.2 million and $266.6 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, 2007 were $4,325.4 million, an increase from $3,661.3 million for the year ended December 31, 2006.

On March 31, 2006 we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale of 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.

During 2007, our Board of Directors authorized a total increase of $300.0 million to our common stock repurchase program. Common stock 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, 2007, we repurchased 4,022,285 shares at a cost of $211.1 million (of which $12.0 million of the cash settlement was after December 31, 2007) or an average of $52.49 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2007, we have repurchased 13,530,906 shares at a cost of $518.1 million or an average of $38.29 per share. At December 31, 2007, we had $181.9 million of authorized repurchases remaining under our program.

RESULTS OF OPERATIONS

Financial Data

		Years Ended December 31,
		2007				2006				2005
		(In thousands, except per share data)
Sales and other revenues		$	4,791,742			$	4,023,217			$	3,046,313
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)			4,003,488				3,349,404				2,498,810
Operating expenses (exclusive of depreciation, depletion and amortization)			209,281				208,460				192,051
General and administrative expenses (exclusive of depreciation, depletion and amortization)			68,773				63,255				51,683
Depreciation, depletion and amortization			43,456				39,721				40,547
Exploration expenses, including dry holes			412				486				481
Total operating costs and expenses			4,325,410				3,661,326				2,783,572
Income from operations			466,332				361,891				262,741
Other income (expense):
Equity in loss of joint ventures			—				—				(685	)
Equity in earnings of HEP			19,109				12,929				6,517
Minority interests in income of partnerships			—				—				(6,721	)
Interest income			15,089				9,757				6,901
Interest expense			(1,086	)			(1,076	)			(5,101	)
			33,112				21,610				911
Income from continuing operations before income taxes			499,444				383,501				263,652
Income tax provision			165,316				136,603				99,626
Income from continuing operations			334,128				246,898				164,026
Income from discontinued operations, net of taxes			—				19,668				2,963
Net income before cumulative effect of change in accounting principle			334,128				266,566				166,989
Cumulative effect of accounting change (net of income tax expense of $426)			—				—				669
Net income		$	334,128			$	266,566			$	167,658
Basic earnings per share:
Continuing operations		$	6.09			$	4.33			$	2.66
Discontinued operations			—				0.35				0.05
Cumulative effect of accounting change			—				—				0.01
Net income		$	6.09			$	4.68			$	2.72
Diluted earnings per share:
Continuing operations		$	5.98			$	4.24			$	2.59
Discontinued operations			—				0.34				0.05
Cumulative effect of accounting change			—				—				0.01
Net income		$	5.98			$	4.58			$	2.65
Cash dividends declared per common share		$	0.46			$	0.29			$	0.19
Average number of common shares outstanding:
Basic			54,852				56,976				61,728
Diluted			55,850				58,210				63,244

Balance Sheet Data

		Years Ended December 31,
		2007				2006
		(In thousands)
Cash, cash equivalents and investments in marketable securities		$	329,784			$	255,953
Working capital		$	216,541			$	240,181
Total assets		$	1,663,945			$	1,237,869
Stockholders’ equity		$	593,794			$	466,094

Other Financial Data

		Years Ended December 31,
		2007				2006				2005
		(In thousands)
Net cash provided by operating activities		$	422,737			$	245,183			$	251,234
Net cash provided by (used for) investing activities		$	(293,057	)		$	35,805			$	(320,135	)
Net cash provided by (used for) financing activities		$	(189,428	)		$	(175,935	)		$	50,505
Capital expenditures		$	161,258			$	120,429			$	106,262
EBITDA from continuing operations (1)		$	528,897			$	414,541			$	302,399

Our sole reportable business segment is Refining after the deconsolidation of HEP effective July 1, 2005. From the closing of the initial public offering of HEP on July 13, 2004 until this deconsolidation, our segments reflected two business segments, Refining and HEP. The HEP segment did not have any activity subsequent to the deconsolidation effective July 1, 2005.

		Years Ended December 31,
		2007				2006				2005
		(In thousands)
Sales and other revenues (1)
Refining		$	4,790,164			$	4,021,974			$	3,028,335
HEP			—				—				36,034
Corporate and other			1,578				1,752				1,772
Consolidations and eliminations			—				(509	)			(19,828	)
Consolidated		$	4,791,742			$	4,023,217			$	3,046,313
Income from operations (1)
Refining		$	537,118			$	425,474			$	296,508
HEP			—				—				16,019
Corporate and other			(70,786	)			(63,583	)			(49,786	)
Consolidated		$	466,332			$	361,891			$	262,741

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, depletion 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,
		2007				2006				2005
Consolidated (7)
Crude charge (BPD) (1)			103,490				96,570				95,950
Refinery production (BPD) (2)			113,270				105,730				106,040
Sales of produced refined products (BPD)			115,050				105,090				106,500
Sales of refined products (BPD) (3)			126,800				119,870				117,110
Refinery utilization (4)			94.1	%			92.4	%			95.0	%
Average per produced barrel (5)
Net sales		$	89.77			$	80.21			$	69.12
Cost of products			73.03				64.43				56.50
Refinery gross margin			16.74				15.78				12.62
Refinery operating expenses (6)			4.43				4.83				4.11
Net operating margin		$	12.31			$	10.95			$	8.51

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, as compared to the year ended December 31, 2006, principally due to an overall increase in refined product margins during the first half of the current year 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 increased by 9% for the year ended December 31, 2007, as compared to the year ended December 31, 2006. Overall refinery gross margins from continuing operations were $16.74 per produced barrel for the year ended December 31, 2007, as compared to refinery gross margins of $15.78 per produced barrel 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 by 9% for the year ended December 31, 2007 as 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, as 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 loss of $0.8 million and a gain of $4.2 million in income in 2007 and 2006, respectively, resulting from the liquidations of certain last-in, first-out (“LIFO”) inventory quantities that were carried at lower costs compared to 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, depletion 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, exclusive of depreciation, depletion 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, Depletion and Amortization Expenses

Depreciation, depletion 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, as 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, as compared to the year ended December 31, 2006.

Interest Income

Interest income for the year ended December 31, 2007 was $15.1 million, as 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 as 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%, as 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.

Results of Operations — Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Summary

Income from continuing operations for the year ended December 31, 2006 was $246.9 million ($4.33 per basic and $4.24 per diluted share) compared to $164.0 million ($2.66 per basic and $2.59 per diluted share) for the year ended December 31, 2005. Income from continuing operations for 2006 as compared to 2005 increased 51% or $82.9 million, due principally to the higher refined product margins experienced throughout much of 2006. Our 2006 earnings also benefited from higher valued refinery yields due to the December 2005 start-up of our ROSE unit, which converts a significant portion of lower value asphalt into high value transportation fuels and the production of all our diesel fuel at both refineries as higher priced Ultra Low Sulfur Diesel (“ULSD”) beginning in July 2006, upon completion of our ULSD capital projects. Furthermore, revenues for the year ended December 31, 2006 include sales of sulfur credits which were generated because our Navajo Refinery is producing gasoline with a substantially lower sulfur content than applicable EPA requirements. These favorable factors were partially offset by the effects of higher operating costs and expenses incurred throughout most of 2006. Refinery production levels from continuing operations were relatively flat for the year ended December 31, 2006 as compared to 2005 primarily due to the offset of reduced production levels during the implementation of our ULSD and expansion projects against higher post-expansion production levels during the latter half of the year. Company-wide refinery margins from continuing operations were $15.78 per produced barrel for the year ended December 31, 2006, as compared to refinery margins of $12.62 per produced barrel for the year ended December 31, 2005.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 32% from $3,046.3 million for the year ended December 31, 2005 to $4,023.2 million for the year ended December 31, 2006, due principally to higher refined product sales prices experienced throughout much of 2006 combined with the recording of direct sales of crude oil as revenues effective April 1, 2006. The average sales price we received per produced barrel sold increased 16% from $69.12 for the year ended December 31, 2005 to $80.21 for the year ended December 31, 2006. The increase

in sales and other revenues for the year ended December 31, 2006 also includes $323.0 million of revenues attributable to certain direct crude oil sales that were previously netted against the corresponding purchases and presented in cost of products sold prior to our adoption of new accounting guidance effective April 1, 2006. Additionally, revenues increased by the sales of $15.9 million for sulfur credits generated because our Navajo Refinery is producing gasoline with a substantially lower sulfur content than applicable EPA requirements.

Cost of Products Sold

Cost of products sold increased 34% from $2,498.8 million in 2005 to $3,349.4 million in 2006 due principally to the higher costs of purchased crude oil and the inclusion of costs attributable to direct crude oil sales. 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 14% from $56.50 in 2005 to $64.43 in 2006. Also, cost of products sold for the year ended December 31, 2006 increased by $323.3 million due to the inclusion of costs attributable to certain excess crude oil sales that were previously netted against the corresponding revenues and included in cost of products sold prior to our adoption of new accounting guidance effective April 1, 2006.

We recognized $4.2 million and $3.0 million in income in 2006 and 2005, respectively, resulting from the liquidations of certain last-in, first-out (“LIFO”) inventory quantities that were carried at lower costs compared to current costs. During 2005, we entered into hedges totaling 1,505,000 barrels covering forecasted diesel fuel sales from November 2005 to February 2006. The positions were liquidated in 2005 resulting in a gain of $3.2 million during 2005, which was recorded as a decrease in cost of products sold.

Refinery Gross Margin

Refining gross margin per produced barrel increased 25% from $12.62 in 2005 to $15.78 in 2006. Refinery gross margin does not include the effects of depreciation, depletion 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, depletion and amortization increased 9% from $192.1 million in 2005 to $208.5 million in 2006 due principally to higher utility costs throughout most of the year and refinery maintenance expense, partially offset by the exclusion of HEP’s operating costs in 2006 due to the deconsolidation of HEP effective July 1, 2005.

General and Administrative Expenses

General and administrative expenses increased 22% from $51.7 million in 2005 to $63.3 million in 2006 due principally to increased equity-based incentive compensation expense.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization decreased 2% from $40.5 million in 2005 to $39.7 million in 2006 due principally to the exclusion of HEP’s depreciation resulting from the deconsolidation of HEP, partially offset by an increase in depreciation arising from capitalized refinery improvement projects in 2006.

Equity in Earnings of HEP and Minority Interests

Our equity in earnings of HEP was $12.9 million and $6.5 million for the years ended December 31, 2006 and 2005, respectively. Prior to July 1, 2005, HEP was a consolidated subsidiary, with the then minority interest partners’ share of HEP’s earnings reported as minority interest. Minority interests in income of HEP for the year ended December 31, 2005 reduced income by $6.7 million.

Equity in Earnings of Joint Ventures

There was no equity in earnings of joint ventures for the year ended December 31, 2006 as all previously owned interests in joint ventures have been consolidated in our financial statements. Equity in earnings of joint ventures for the year ended December 31, 2005 was a loss of $0.7 million, reflecting our interest in the NK Asphalt joint venture prior to our acquisition of the other partner’s interest.

Interest Income

Interest income for the year ended December 31, 2006 was $9.8 million as compared to $6.9 million for the year ended December 31, 2005. The increase in interest income was principally due to the effects of a higher interest rate environment on increased internally generated cash throughout 2006.

Interest Expense

Interest expense was $1.1 million for the year ended December 31, 2006 as compared to $5.1 million for the year ended December 31, 2005. The decrease for 2006 as compared to 2005 was principally due to the exclusion of HEP’s interest expense in 2006 due to the deconsolidation of HEP effective July 1, 2005.

Income Taxes

Income taxes increased 37% from $99.6 million in 2005 to $136.6 million in 2006 due to significantly higher pre-tax earnings in 2006 as compared to 2005, partially offset by a lower effective tax rate. The effective tax rate for 2006 was 35.6%, as compared to 37.8% for 2005. The Company’s effective tax rate decreased in 2006 as compared to 2005 primarily due to the impact of the American Jobs Creation Act of 2004, which provides tax incentives for small business refiners incurring costs to produce ultra low sulfur diesel fuel and a 3% deduction for income derived from domestic manufacturing activities.

Discontinued Operations

Income from discontinued operations was $19.7 million for the year ended December 31, 2006 as compared to $3.0 million for the year ended December 31, 2005. Included in income for the year ended December 31, 2006 was the gain on the sale of the Montana Refinery of $14.0 million, net of $8.3 million in income taxes. The operations of the Montana Refinery generated $5.7 million of earnings in 2006 as compared to $3.0 million in 2005. The increase in earnings from discontinued operations was also due in part to the liquidation in 2006 of retained finished product inventories relating to the Montana Refinery that had been carried at lower costs as compared to current values.

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. VRDN may be liquidated at par on the rate reset date. Currently, we do not invest in auction rate securities. 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, 2007, we had cash and cash equivalents of $94.4 million, marketable securities with maturities under one year of $158.2 million and marketable securities with maturities greater than one year, but less than two years, of $77.2 million.

Cash and cash equivalents decreased by $59.7 million during 2007. The combined cash used for investing and financing activities of $293.1 million and $189.4 million, respectively, exceeded cash provided by operating activities of $422.7 million. Working capital decreased by $23.6 million during 2007.

We have a $175.0 million secured revolving credit facility with Bank of America as administrative agent and a lender, with a term of four years through July 2008 and an option to increase it to $225.0 million subject to certain conditions. We expect to close on an extension to the credit facility in the first quarter of 2008. The credit facility may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes. As of December 31, 2007, we had letters of credit outstanding under our revolving credit facility of $2.5 million and had no borrowings outstanding. We were in compliance with all covenants at December 31, 2007.

During 2007, our Board of Directors authorized a total increase of $300.0 million to our common stock repurchase program. Common stock 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, 2007, we repurchased 4,022,285 shares at a cost of $211.1 million (of which $12.0 million of the cash settlement was after December 31, 2007) or an average of $52.49 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2007, we have repurchased 13,530,906 shares at a cost of $518.1 million or an average of $38.29 per share. At December 31, 2007, we had $181.9 million of authorized repurchases remaining under our program.

We believe our current cash, cash equivalents and marketable securities, along with future internally generated cash flow and funds available under our credit facility 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 the repurchase of additional common stock under our common stock repurchase program. 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.

Since HEP is no longer consolidated in our financial statements effective July 1, 2005, we no longer include the accounts of HEP in our consolidated financial statements, and our share of the earnings of HEP is now reported using the equity method of accounting. Accordingly, the HEP Senior Notes are not recorded on our accompanying consolidated balance sheet at December 31, 2007. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s general partner to the extent it makes any payment in satisfaction of $35.0 million of the principal amount of the HEP Senior Notes.

Cash Flows — Operating Activities

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, as 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 as compared to $31.4 million for the year ended December 31, 2006. Distributions in excess of equity in earnings of Holly Energy Partners decreased to $3.7 million for the year ended December 31, 2007 as compared to $7.4 million for the year ended December 31, 2006. Working capital items increased cash flows by $15.0 million in 2007, as compared to a decrease of $40.9 million in 2006. For the year ended December 31, 2007, inventories increased by $11.0 million, as 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, as compared to a decrease of $12.1 million for 2006 and accounts payable increased by $264.2 million, as compared to a decrease of $26.4 million for 2006.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Net cash flows provided by operating activities were $245.2 million for 2006, as compared to $251.2 million for 2005, a decrease of $6.0 million. Net income in 2006 was $266.6 million, an increase of $98.9 million from net income of $167.7 million for 2005. The non-cash items of depreciation and amortization, deferred taxes, minority interests, equity-based compensation and gain on sale of assets resulted in an increase to operating cash flows of $31.4 million for the year ended December 31, 2006 as compared to $46.9 for the year ended December 31, 2005. Distributions in excess of equity in earnings of Holly Energy Partners and joint ventures increased by $4.3 million for the year ended December 31, 2006 from the year ended December 31, 2005. Working capital items decreased cash flows by $40.9 million in 2006, as compared to an increase of $35.9 million in 2005. For 2006, accounts receivable and accounts payable decreased $12.1 million and $26.4 million, respectively, as compared to 2005 accounts receivable and accounts payable increases of $128.3 million and $143.3 million, respectively.

Cash Flows — Investing Activities and Planned Capital Expenditures

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 as 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 as 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 the sales and maturities of marketable securities. This compared to investments of $212.0 million in marketable securities and $319.3 million of proceeds received from sales and maturities of marketable securities in 2006. Furthermore in 2006, we received cash proceeds of $48.9 million following the sale of our Montana Refinery on March 31, 2006.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Net cash flows provided by investing activities were $35.8 million for 2006 as compared to net cash flows used for investing activities of $320.1 million for 2005, an increase of $355.9 million. Cash expenditures for property, plant and equipment for 2006 totaled $120.4 million as compared to $106.3 million for 2005. Capital expenditures in 2006 related primarily to the completion of the ULSD / expansion projects at the Navajo Refinery and the ULSD project at the Woods Cross Refinery that were initiated in 2005. We received cash proceeds of $48.9 million following the sale of the Montana Refinery to Connacher on March 31, 2006. We also invested $212.0 million in marketable securities and received proceeds of $319.3 million from sales and maturities of marketable securities during 2006. Most of the 2005 expenditures were for the ULSD / expansion projects at the Navajo Refinery, the ULSD project at the Woods Cross Refinery and an asphalt unit at the Navajo Refinery. On February 28, 2005, HEP closed on its Alon transaction which required $120.0 million in cash plus transaction costs of $1.9 million. Upon the deconsolidation of HEP, we no longer include the cash of HEP in our consolidated financial statements, and therefore the HEP cash balance at June 30, 2005 is shown as a use of cash. In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by the other partner. The total purchase consideration for the 51% interest, including expenses, was $21.8 million, less cash of $3.4 million which was recorded due to the consolidation of NK Asphalt Partners at the time of our acquisition of the remaining 51% interest. We also invested $322.0 million in marketable securities and received proceeds of $268.0 million from sales and maturities of marketable securities during 2005.

Planned Capital Expenditures

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 2008 is approximately $37.5 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 2008 capital budget is comprised of $21.0 million for refining improvement

projects for the Navajo Refinery, $7.7 million for projects at the Woods Cross Refinery, $1.6 million for marketing-related projects, $2.0 million for asphalt plant projects and $5.2 million for other miscellaneous projects.

At the Navajo Refinery, we will be installing a new 15,000 BPD hydrocracker and a new 28 MMSCFD hydrogen plant at a budgeted cost of approximately $125.0 million. The addition of these units is expected to increase liquid volume recovery, increase the refinery’s capacity to process outside feedstocks, and increase yields of high valued products, as well as enabling the refinery to meet new low sulfur gasoline specifications required by the Environmental Protection Agency (“EPA”). The hydrocracker and hydrogen plant projects will provide improved heavy crude oil processing flexibility.

As announced in February 2007, we are revamping an existing crude unit which will increase the crude capacity at the Navajo Refinery to approximately 100,000 BPD. Additionally, our Board of Directors has approved a revamp of its second crude unit and a new solvent de-asphalter unit. The approved components, combined with the above described components approved in 2006, bring the total budgeted amount for this expansion and heavy crude oil processing project to $245.0 million. It is currently anticipated that the expansion portion of the overall project consisting of the initial crude unit revamp, the new hydrocracker and the new hydrogen plant will be completed and operational by the first quarter of 2009. The completion of the heavy crude oil processing portion of the overall project, including the second crude unit revamp and the installation of the new solvent de-asphalter, will be targeted to coincide with the development of future pipeline access to the Navajo Refinery for heavy Canadian crude oil and other foreign heavy crude oils transported from the Cushing, Oklahoma area. We plan to explore with HEP the most economical manner to obtain this needed pipeline access.

Also at the Navajo Refinery, a project to install an additional 100 ton per day sulfur recovery unit included in the 2006 capital budget is currently underway at an estimated cost of $26.0 million, of which we have spent approximately $10.0 million to date. This new sulfur recovery unit will permit our Navajo Refinery to process 100% sour crude and is planned for start-up in the third quarter of 2008. It is anticipated that the projects that will be completed by the fourth quarter of 2008 will also enable the Navajo Refinery, without significant additional investment, to comply with LSG specifications required by the end of 2010.

At the Woods Cross Refinery, we will be adding a new 15,000 BPD hydrocracker along with sulfur recovery and desalting equipment at our Woods Cross Refinery. The budgeted cost of these additions is approximately $105.0 million. These additions will expand the Woods Cross Refinery’s crude processing capabilities from 26,000 BPD to 31,000 BPD while enabling the refinery to process up to 10,000 BPD of high-value low-priced black wax crude oil and up to 5,000 BPD of low-priced heavy Canadian crude oils. This expansion project as approved involves a higher capital investment than had originally been estimated, principally because of the substitution of a complex hydrocracker in place of certain desulfurization and expanded bottoms-processing modifications that had been included in preliminary planning. The substitution of the complex hydrocracker is expected to provide increased capabilities to process significantly more black wax crude oils, which have recently been priced at substantial discounts to West Texas Intermediate crude oil while yielding substantially higher value products than the discounted heavy Canadian crudes that were a more significant part of the original plan. These additions would also increase the refinery’s capacity to process low-cost feedstocks and provide the necessary infrastructure for future expansions of crude oil refining capacity at the Woods Cross Refinery. The approved projects for the Woods Cross refinery are expected to be completed during the fourth quarter of 2008.

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. In November 2007, HEP entered into an agreement with Plains All American Pipeline, L.P. 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 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, which is currently flowing on Plains’ Rocky Mountain Pipeline. The project is currently expected to be fully operational by the second quarter of 2008.

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 will own 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. Holly’s share of this cost is $225.0 million. Construction of this project is currently expected to be completed and operational in mid 2009. 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 our equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum.

In 2008, we expect to expend approximately $450.0 million on currently approved refinery capital projects, which 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 provides 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. We estimate the tax savings that we derive from planned capital expenditures associated with the 2004 Act will result in a reduction in our income tax expense of approximately $1.3 million in 2008, representing the difference between the value of allowed credits under the 2004 Act as compared to the value of depreciating the investments. In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act creates 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 expansions under the new Navajo and Woods Cross capital projects will 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.

Cash Flows — Financing Activities

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, as compared to net cash flows used for financing activities of $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.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Net cash flows used by financing activities were $175.9 million for 2006, as compared to net cash flows provided by financing activities of $50.5 million for 2005, a decrease of $226.4 million. Under our common stock repurchase program, we purchased treasury stock of $175.4 million in 2006. We also 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 2006. Our 2005 financing activities include the activities of HEP prior to our deconsolidation of HEP effective July 1, 2005. In connection with HEP’s Alon asset acquisition on February 28, 2005, HEP received proceeds of $147.4 million from the issuance of HEP Senior Notes. In connection with HEP’s purchase of our intermediate lines, HEP received proceeds of $34.6 million from additional issuance of their HEP Senior Notes, and raised $43.8 million, net of offering costs, from the private sale of 1.1 million of its common units to a limited number of institutional investors, which closed simultaneously with the acquisition.

Additionally during 2005, we made our final scheduled repayment of long-term debt of $8.6 million, paid $11.2 million in dividends, received $2.8 million for common stock issued upon exercise of stock options, made distributions of $1.6 million to the minority interest partner of Rio Grande, made distributions of $7.9 million to the minority interests holders of HEP, paid down borrowings under HEP’s credit facility netting to $25.0 million, incurred $0.9 million of debt issuance costs related to HEP’s senior debt and recognized $6.0 million in excess tax benefits on our equity based compensation. Under our $200.0 million stock repurchase program, we purchased treasury stock of $30.0 million and under our $100.0 million stock repurchase program, we purchased treasury stock of $100.0 million. Also, during 2005, we repurchased at current market price from certain executives 24,790 shares of our common stock at a cost of approximately $0.8 million; these purchases were made under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2007 in total and by period due beginning in 2008. 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(4)(5)		Total				1 Year				2-3 Years				4-5 Years				5 Years
		(In thousands)
Operating leases		$	9,103			$	2,774			$	4,663			$	1,493			$	173
Minimum revenue agreements with HEP (1)		$	615,350			$	52,398			$	104,796			$	104,796			$	353,360
Hydrogen supply agreement(2)		$	128,105			$	—			$	17,081			$	17,081			$	93,943
Other service agreements(3)		$	16,335			$	2,382			$	4,412			$	3,858			$	5,683

HEP financed the Alon transaction through a private offering of $150.0 million principal amount of HEP Senior Notes. HEP increased these notes to $185.0 million as part of the purchase of our intermediate pipelines. The $185.0 million HEP Senior Notes are not recorded on our accompanying consolidated balance sheet at December 31, 2006 due to the deconsolidation of HEP effective July 1, 2005. The HEP Senior Notes were reflected on our consolidated balance sheet (because HEP was a consolidated subsidiary) through June 30, 2005. Navajo Pipeline

Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s general partner to the extent it makes any payment in satisfaction of $35.0 million of the principal amount of the HEP Senior Notes.

In December 2001, we entered into a Consent Agreement with the EPA and the New Mexico Environment Department of Environmental Quality with respect to a global settlement of issues concerning the application of air quality requirements to past and future operations of our Navajo Refinery. The Consent Agreement requires us to make investments at our Navajo Refinery for the installation of certain state of the art pollution control equipment expected to total approximately $14.0 million. With the investments made to date, our outstanding required investment is no longer significant.

Under the March 31, 2005 Asset Purchase Agreement entered into with Connacher’s subsidiary by our subsidiaries MRC, Black Eagle, Inc. and Navajo Northern, Inc., whose obligations we guaranteed, we retained certain financial liabilities, including certain environmental liabilities related to required remediation and corrective action for environmental conditions that existed at the time of sale and for financial penalties for infractions that occurred prior to the sale. Our agreement provides that environmental claims must be made within 5 years of the sale and provides for a maximum liability of $41.0 million for any matter other than fraud and a deductible of $400,000. In addition, we have continuing obligations with respect to assets that were not transferred in our sale of the refinery. Based on our estimates, we recorded a liability of $2.2 million for such environmental liabilities, of which $0.2 million has been expended to date.

CRITICAL ACCOUNTING POLICIES

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

Inventory Valuation

Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years such as 2007 when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2007, our LIFO inventory layers were valued at historical costs that were established in years when price levels were much lower; therefore, our results of operation are less sensitive to current market price reductions. As of December 31, 2007, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $199.4 million. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation.

Deferred Maintenance Costs

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

maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit.

Long-lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2007, 2006 and 2005.

Investment in HEP

FIN 46 (revised December 2003) defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity, or have voting rights that are not proportionate to their economic interests. This standard requires a company to consolidate a variable interest entity (“VIE”) if it is allocated a majority of the entity’s expected losses or expected residual returns. HEP is a VIE as defined under FIN 46, and following HEP’s acquisition of our intermediate feedstock pipelines in July 2005, we determined that our beneficial variable interest in HEP was less than 50%. As required by FIN 46, we have deconsolidated HEP effective as of July 1, 2005. The deconsolidation is being presented from July 1, 2005 forward, and our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, is now reported using the equity method of accounting. HEP has risk associated with its operations. HEP has three major customers, one being us. If any of the customers fails to meet the desired shipping levels or terminates its contracts, HEP could suffer substantial losses unless a new customer is found. If HEP does suffer losses, we would recognize our percentage of those losses based on our ownership percentage at that time.

On February 26, 2008, we announced an agreement for the sale of certain pipeline and tankage assets to HEP for $180.0 million. The agreement provides for consideration to us of $171.0 million in cash and HEP common units valued at approximately $9.0 million. The assets include 136 miles of crude oil trunk lines that deliver crude to our Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000 barrels of storage capacity located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support our Woods Cross Refinery. In connection with the closing of this transaction, we will enter into a 15-year pipelines and tankage agreement with HEP that will contain a minimum annual revenue commitment to HEP from us. This transaction is expected to close on February 29, 2008. We expect the consummation of this proposed transaction to result in our owning a beneficial variable interest in HEP in excess of 50%. In accordance with provisions under FIN 46, we expect to reconsolidate HEP effective March 1, 2008.

Contingencies

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

New Accounting Pronouncements

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51” In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred

to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. We will adopt this standard effective January 1, 2009. We are currently evaluating the impact of this standard on our financial condition, results of operations and cash flows.

EITF No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
In June 2007, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. EITF No. 06-11 requires that tax benefits generated by dividends paid during the vesting period on certain equity-classified share-based compensation awards be classified as additional paid-in capital and included in a pool of excess tax benefits available to absorb tax deficiencies from share-based payment awards. EITF No. 06-11 is effective for fiscal years beginning after December 15, 2007. We will adopt this standard effective for our 2008 fiscal year. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No 115. SFAS No. 159, which amends SFAS No. 115, allows certain financial assets and liabilities to be recognized, at a company’s election, at fair market value, with any gains or losses for the period recorded in the statement of income.  SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and interim periods in those fiscal years.   We will adopt this standard effective January 1, 2008. We do not expect the adoption of this statement to have a material impact on our financial condition, results of operations and cash flows.

SFAS No. 157 “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. This standard is effective for fiscal years beginning after November 15, 2007. We will adopt this standard effective for our 2008 fiscal year. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective January 1, 2007. As a result of the implementation of this standard, we recognized no material adjustment in the liability for unrecognized income tax benefits.

We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.

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

RISK MANAGEMENT

Historically, we have used certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit. Our profitability depends largely on the spread between market prices for refined products and market prices for crude oil. A substantial or prolonged reduction in this spread could have a significant negative effect on our earnings, financial condition and cash flows.

We have utilized petroleum commodity futures contracts to reduce our exposure to price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. We regularly utilize contracts that provide for the purchase of crude oil and other feedstocks and for the sale of refined products. Certain of these contracts may meet the definition of a derivative instrument in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. We believe these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, because deliveries under the contracts will be in quantities expected to be used or sold over a reasonable period of time in the normal course of business. Accordingly, these contracts are designated as normal purchases and normal sales contracts and are not required to be recorded as derivative instruments under SFAS No. 133.

During 2005, we entered into two different types of hedging transactions, neither of which involved arrangements designated as hedging instruments per the requirements of SFAS No. 133, and therefore all gains and losses were recorded as incurred. The first transaction was entered into in July 2005 and related to our forecasted August 2005 liquidation of 100,000 barrels of crude oil at our Woods Cross Refinery, where our objective was to fix the price of crude oil associated with the liquidation. To affect the hedge, we sold crude oil futures contracts in July 2005 and liquidated the positions in August 2005 matching when the crude oil inventory was slated for production. We recognized a loss of $0.5 million on this transaction and recorded it as an increase in cost of products sold. The other type of transaction we have entered into from time to time starting in July 2005 relates to forecasted sales of diesel fuel from our refineries, where our principal objective is to take advantage of the higher margins (or crack spreads, being the difference between the price of diesel fuel and the cost of crude oil) on a portion of our diesel fuel sales. To effect these hedges, we sold heating oil futures (which most closely match diesel fuel pricing) and bought crude oil futures. We have also entered into commodity swap transactions (the terms of which mirror the futures contracts entered into) to effect the same strategy on a portion of these hedges. Our objective is either to liquidate the positions as the crack spreads return to more normalized levels, or to hold these positions until the forecasted diesel fuel sales are made, effectively locking in the diesel fuel crack spreads (or margins) at the high levels. Our strategy is to enter into these transactions only when the margins are at historically very high levels, and to have no more than 25% of our diesel fuel production hedged at any given time. During 2005, we entered into hedges totaling 1,505,000 barrels covering forecasted diesel fuel sales from November 2005 to February 2006. The positions were fully liquidated during August to November 2005 resulting in a realized gain of $3.2 million, which was recorded as a decrease in cost of products sold.

At December 31, 2007, we had no outstanding debt. As the interest rates on our bank borrowings are reset frequently based on either the bank’s daily effective prime rate, or the LIBOR rate, interest rate market risk on any bank borrowings would be very low. At times, we have used borrowings under our credit facility to finance our working capital needs. There were no borrowings under the credit facilities at December 31, 2007. We invest certain available cash primarily in investment grade, highly liquid investments with maturities of three months or less and in portfolios of highly rated marketable debt securities, primarily issued by government entities, that have an average remaining duration (including any cash equivalents invested) of not greater than one year and hence the interest rate market risk implicit in these investments is low. A hypothetical 10% change in the market interest rate over the next year would not materially impact our earnings, cash flow or financial condition since any borrowings under the credit facilities and investments are at market rates and such interest has historically not been significant as compared to our total operations.

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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

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

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

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

		Years Ended December 31,
		2007				2006				2005
		(In thousands)
Income from continuing operations		$	334,128			$	246,898			$	164,026
Add provision for income tax			165,316				136,603				99,626
Add interest expense			1,086				1,076				5,101
Subtract interest income			(15,089	)			(9,757	)			(6,901	)
Add depreciation, depletion and amortization			43,456				39,721				40,547
EBITDA from continuing operations		$	528,897			$	414,541			$	302,399

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

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

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

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

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

		Years Ended December 31,
		2007				2006				2005
Average per produced barrel:
Navajo Refinery
Net sales		$	89.68			$	79.62			$	69.11
Less cost of products			74.10				64.25				55.50
Refinery gross margin		$	15.58			$	15.37			$	13.61
Woods Cross Refinery
Net sales		$	90.09			$	82.09			$	69.13
Less cost of products			69.40				64.99				59.51
Refinery gross margin		$	20.69			$	17.10			$	9.62
Consolidated
Net sales		$	89.77			$	80.21			$	69.12
Less cost of products			73.03				64.43				56.50
Refinery gross margin		$	16.74			$	15.78			$	12.62

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

		Years Ended December 31,
		2007				2006				2005
Average per produced barrel:
Navajo Refinery
Refinery gross margin		$	15.58			$	15.37			$	13.61
Less refinery operating expenses			4.30				4.74				3.94
Net operating margin		$	11.28			$	10.63			$	9.67
Woods Cross Refinery
Refinery gross margin		$	20.69			$	17.10			$	9.62
Less refinery operating expenses			4.86				5.13				4.61
Net operating margin		$	15.83			$	11.97			$	5.01
Consolidated
Refinery gross margin		$	16.74			$	15.78			$	12.62
Less refinery operating expenses			4.43				4.83				4.11
Net operating margin		$	12.31			$	10.95			$	8.51