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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2005


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

For the transition period from to

Commission File Number 1-3876

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)


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

100 Crescent Court, Suite 1600, Dallas, Texas (Address of principle executive offices)		75201-6927 (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. þ

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

Large accelerated filer þ Accelerated filer o Non-accelerated filer 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, 2005 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $1,040,000,000. (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.)

29,377,471 shares of Common Stock, par value $.01 per share, were outstanding on February 14, 2006.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 11, 2006, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005, are incorporated by reference in Part III.

PART I

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

	•		effects of governmental regulations and policies;

	•		the availability and cost of our financing;

	•		the effectiveness of our capital investments and marketing strategies;

	•		our efficiency in carrying out construction projects;

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

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

	•		general economic conditions; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation in conjunction with the forward-looking statements included in this Form 10-K that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K in “Risk Factors” under 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.

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DEFINITIONS

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

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

“BPD” means the number of barrels per 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 fractionated directly from crude oil to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is the main 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 the breaking down of large, complex hydrocarbon molecules into smaller, more useful ones by the application of heat, pressure and a chemical (catalyst) to speed the process.

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

“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 converting C5/C6 gasoline compounds into their isomers, i.e., rearranging the structure of the molecules without changing their size or chemical composition.

“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.

“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.

“Refining gross margin” or “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.

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Items 1 and 2. Business and Properties

COMPANY OVERVIEW

References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In this document, the words “we”, “our”, “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

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 75201-6927. 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 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. (“FIN”) 46 (revised), “Consolidation of Variable Interest Entities,” 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, 2005, we:

	•		owned and operated three refineries consisting of a petroleum refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively known as the “Navajo Refinery”), and refineries in Woods Cross, Utah and Great Falls, Montana;

	•		owned approximately 800 miles of crude oil pipelines located principally in West Texas and New Mexico;

	•		owned 100% of NK Asphalt Partners which manufactures and markets asphalt products from various terminals in Arizona and New Mexico and does business under the name of “Holly Asphalt Company;” and

	•		owned a 45.0% interest in HEP (which includes our 2.0% general partnership interest), which has logistics assets including approximately 1,400 miles of petroleum product pipelines located in Texas, New Mexico and Oklahoma (including 340 miles of leased pipeline); eleven refined product terminals; two refinery truck rack facilities, a refined products tank farm facility and a 70% interest in Rio Grande.

Navajo Refining Company, L.P., one of our wholly-owned subsidiaries, owns the Navajo Refinery. The Navajo Refinery has a crude capacity of 75,000 BPSD, can process sour crude oils and serves markets in the southwestern United States and northern Mexico. In June 2003, we acquired the Woods Cross refining facility from ConocoPhillips. The Woods Cross refinery (“Woods Cross Refinery”), located just north of Salt Lake City, has a crude capacity of 26,000 BPSD and is operated by Holly Refining & Marketing Company – Woods Cross, one of

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our wholly-owned subsidiaries. This facility is a high conversion refinery that processes regional sweet and Canadian sour crude oils. We also own Montana Refining Company, which owns an 8,000 BPSD petroleum refinery in Great Falls, Montana (“Montana Refinery”), which processes primarily Canadian sour crude oils and which primarily serves markets in Montana. In conjunction with the refining operations, we own approximately 800 miles of pipelines that serve primarily as the supply network for our refineries.

As announced on March 2, 2006, we have entered into a definitive agreement with Connacher Oil and Gas Limited (“Connacher”) for the sale of the Montana Refinery. The purchase price for the assets including inventories is estimated at approximately $55 million, subject to certain closing adjustments, and includes 1,000,000 shares of Connacher common stock currently valued at approximately $4 million. The consummation of the sale is subject to certain conditions, and we expect the closing to occur on or before April 1, 2006. The amount recorded on our balance sheet at December 31, 2005 for the net assets scheduled to be sold under the definitive agreement is approximately $20 million.

Our operations are currently organized into one business division, Refining. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and NK Asphalt Partners. Prior to our deconsolidation of HEP on July 1, 2005 our operations were organized into two business divisions, which were Refining and HEP. Our operations that are not included in either the Refining or HEP (prior to its deconsolidation) business divisions 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, the Woods Cross Refinery and the Montana Refinery. The following table sets forth information about our combined refinery operations, including non-GAAP performance measures for 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 under Part II of this Form 10-K. Information regarding our individual refineries is provided under “Operating Data – Refining Operations” in Item 7 of this Form 10-K.


	Years Ended December 31,
	2005			2004			2003⁽⁸⁾
*Consolidated*
Crude charge (BPD) ⁽¹⁾		103,840			102,230			76,040
Refinery production (BPD) ⁽²⁾		114,410			111,070			85,030
Sales of produced refined products (BPD)		114,900			110,370			82,900
Sales of refined products (BPD) ⁽³⁾		125,680			118,760			95,420

Refinery utilization ⁽⁴⁾		95.3	%		94.7	%		93.2	%

Average per produced barrel ⁽⁵⁾
Net sales	$	67.99		$	50.80		$	38.99
Cost of products ⁽⁶⁾		55.53			41.70			31.76

Refinery gross margin		12.46			9.10			7.23
Refinery operating expenses ⁽⁷⁾		4.30			3.53			3.58

Net operating margin	$	8.16		$	5.57		$	3.65


Feedstocks:
Sour crude oil		68	%		67	%		66	%
Sweet crude oil		20	%		23	%		23	%
Other feedstocks and blends		12	%		10	%		11	%

Total		100	%		100	%		100	%

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

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other feedstocks at our refineries.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD).

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

(6)		Subsequent to the formation of HEP, transportation costs billed from HEP are included in cost of products.

(7)		Represents operating expenses of our refineries, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

(8)		We acquired the Woods Cross Refinery on June 1, 2003, and we are reporting amounts for Woods Cross only for periods since the purchase date.

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,
	2005			2004			2003
*Consolidated*
Sales of produced refined products:
Gasolines		58	%		58	%		57	%
Diesel fuels		26	%		27	%		23	%
Jet fuels		4	%		4	%		8	%
Asphalt		7	%		7	%		8	%
LPG and other		5	%		4	%		4	%

Total		100	%		100	%		100	%

We have several significant customers, none of which account for more than 10% of our business. Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, an affiliate of Petr\leos 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 primarily for military use. Asphalt is sold to governmental entities or contractors. Carbon black oil is sold for further processing, and LPG’s are sold to LPG wholesalers and LPG retailers. 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. We believe that the availability of significant capacity in HEP’s pipeline transportation system to the Albuquerque area and northern New Mexico increases our flexibility in the event of the loss of a major current purchaser of products for retail sales.

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.

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Navajo Refinery

Facilities

The Navajo Refinery has a crude oil capacity of 75,000 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 90% of its raw materials throughput into high value light products. For 2005, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 59%, 27% and 4%, 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 under Generally Accepted Accounting Principles” following Item 7A under Part II of the Form 10-K.


	Years Ended December 31,
	2005			2004			2003
*Navajo Refinery*
Crude Charge (BPD) ⁽¹⁾		71,850			71,060			56,080
Refinery production (BPD) ⁽²⁾		80,190			79,330			63,680
Sales of produced refined products (BPD)		80,110			78,880			62,570
Sales of refined products (BPD) ⁽³⁾		89,400			86,410			74,500

Refinery utilization ⁽⁴⁾		95.8	%		94.7	%		93.5	%

Average per produced barrel ⁽⁵⁾
Net sales	$	69.11		$	51.42		$	38.95
Cost of products ⁽⁶⁾		55.50			41.26			31.52

Refinery gross margin		13.61			10.16			7.43
Refinery operating expenses ⁽⁷⁾		3.94			3.20			3.24

Net operating margin	$	9.67		$	6.96		$	4.19


Feedstocks:
Sour crude oil		85	%		83	%		78	%
Sweet crude oil		2	%		5	%		10	%
Other feedstocks and blends		13	%		12	%		12	%

Total		100	%		100	%		100	%


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

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other feedstocks at the refinery.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD).

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

(6)		Subsequent to the formation of HEP, transportation costs billed from HEP are included in cost of products.

(7)		Represents operating expenses of the refinery, exclusive of depreciation, depletion, and amortization and excludes refining segment expenses of product pipelines and terminals.

Navajo Refining’s Artesia, New Mexico facility is located on a 410 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 1.8 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 1.0 million barrels of feedstock and product tankage. The Lovington facility

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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 75,000 BPSD and typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.

We have approximately 800 miles of crude gathering pipelines transporting crude oil to the Artesia and Lovington facilities from various points in southeastern New Mexico and West Texas, 66 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 to El Paso, Texas. In addition, we use a pipeline 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 Albuquerque, Artesia, Moriarty and Bloomfield, New Mexico.

In 2000, we formed a joint venture, NK Asphalt Partners, with a subsidiary of Koch Materials Company (“Koch”) to manufacture and market asphalt and asphalt products in Arizona and New Mexico under the name “Koch Asphalt Solutions – Southwest.” We contributed our asphalt terminal and asphalt blending and modification assets in Arizona to NK Asphalt Partners and Koch contributed its New Mexico and Arizona asphalt manufacturing and marketing assets to NK Asphalt Partners. On January 1, 2002, we sold a 1% equity interest in NK Asphalt Partners to Koch thereby reducing our equity interest from 50% to 49%. In February 2005, we purchased the 51% interest owned by Koch in NK Asphalt Partners for $16.9 million plus working capital of approximately $5 million. This purchase increased our ownership in NK Asphalt Partners from 49% to 100%. Following the purchase of the 51% interest from Koch, NK Asphalt Partners does business under the name “Holly Asphalt Company.”

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 Chevron Pipeline Company 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 leased pipeline running from Chaves County to San Juan County, New Mexico.

The El Paso Market

A majority of the light products of the Navajo Refinery (i.e. products other than asphalt, LPG’s and carbon black oil) are currently shipped to El Paso on pipelines that HEP owns and operates. Of the products shipped to El Paso, most are subsequently shipped (either by us or by purchasers of our products) via common carrier pipelines to Tucson and Phoenix, Arizona. A smaller percentage of our light products is shipped to Albuquerque, New Mexico and markets in northern Mexico via common carrier pipelines; the remaining products that are shipped to El Paso are sold to wholesale customers primarily for ultimate retail sale in the El Paso area. We expanded our capacity to supply El Paso in 1996 when we replaced most of an 8-inch pipeline from Orla to El Paso, Texas with a new 12-inch line, a portion of the throughput of which has been leased to Alon USA LP (“Alon”), owner of the Fina brand, to transport refined products from the Alon refinery in Big Spring, Texas to El Paso. HEP currently receives monthly payments from Alon with respect to the long term lease of this pipeline.

The El Paso market for refined products is currently supplied by a number of refiners that either are located in El Paso or have pipeline access to El Paso. These include the ConocoPhillips and Valero refineries in the Texas panhandle and the Western refinery in El Paso. We currently supply approximately 54,000 BPD into the El Paso market, 13,500 BPD of which are consumed in the local El Paso market. Since 1995, the volume of refined products transported by various suppliers via pipeline to El Paso has substantially expanded, in part as a result of our own 12-inch pipeline expansion described above and primarily as a result of the completion in November 1995 of the Valero L.P. 10-inch pipeline running 408 miles from the Valero refinery near McKee, Texas to El Paso. The capacity of this pipeline (in which ConocoPhillips now owns a one-third interest) is currently 60,000 BPD. We

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believe that demand in the El Paso market and more importantly the larger Arizona markets served through El Paso will continue to grow.

Until 1998, the El Paso market and markets served from El Paso were generally not supplied by refined products produced by the large refineries on the Texas Gulf Coast. While wholesale prices of refined products on the Gulf Coast have historically been lower than prices in El Paso, distances from the Gulf Coast to El Paso (more than 700 miles by the most direct route) have made transportation by truck unfeasible and would require substantial investment to develop refined products pipelines from the Gulf Coast to El Paso.

In 1998, a Texaco, Inc. subsidiary converted an existing 16-inch crude oil pipeline that runs from the Gulf Coast to Midland, Texas along a northern route through Corsicana, Texas to refined products service. This pipeline, now owned by Magellan Midstream Partners, L.P. (“Magellan”), is linked to a 6-inch pipeline, also owned by Magellan, that can transport to El Paso approximately 18,000 to 20,000 BPD of refined products produced on the Texas Gulf Coast (this capacity had previously been used to transport volumes produced by a Shell Oil Company refinery in Odessa, Texas, which was shut down in 1998). The Magellan pipeline from the Gulf Coast to Midland has the potential to link to existing or new pipelines running from the Midland, Texas area to El Paso that could result in substantial additional volumes of refined products being transported from the Gulf Coast to El Paso.

The Longhorn Pipeline

The Longhorn Pipeline, which is owned by Longhorn Partners Pipeline, L.P. (“Longhorn Partners”), is a new source of pipeline transportation from Gulf Coast refineries to El Paso. This pipeline is approximately 700 miles and runs from the Houston area of the Gulf Coast to El Paso, utilizing a direct route. Longhorn Partners has announced that it would use the pipeline initially to transport approximately 72,000 BPD of refined products from the Gulf Coast to El Paso and markets served from El Paso, with an ultimate maximum capacity of 225,000 BPD. Since inception of Longhorn Pipeline operations in late 2005, it is our understanding that there have been some limited shipments (substantially under the 72,000 BPD rate) of refined products. Although the Longhorn Pipeline has had very limited impact on us to date, if the Longhorn Pipeline is ever able to operate as has been proposed and significantly increases the volumes of refined products it transports, downward pressure on wholesale refined products margins in El Paso and related markets could result. However, any effects on our markets in Tucson and Phoenix, Arizona and Albuquerque, New Mexico would be expected to be limited in the near-term because current common carrier pipelines from El Paso to these markets are now running at capacity and proration policies of these pipelines allocate only limited capacity to new shippers. Although ChevronTexaco has not announced any plans to expand their common carrier pipeline from El Paso to Albuquerque to address their capacity constraint, SFPP is currently expanding the capacity of its pipeline from El Paso to the Arizona market by between 45,000 and 50,000 BPD. SFPP has announced an expected completion date of April 2006 for this first expansion. Additionally, SFPP announced a further planned expansion of the capacity of this pipeline from El Paso to the Arizona market by 23,000 BPD, with an expected completion date in the summer of 2007. Although our results of operations might be adversely impacted by the Longhorn Pipeline and by the expansions of SFPP’s El Paso-to-Arizona pipeline, we are unable to predict at this time the extent to which we could be negatively affected.

Arizona and Albuquerque Markets

We currently supply approximately 32,000 BPD of refined products into the Arizona market, comprised primarily of Phoenix and Tucson, which accounts for approximately 14% of the refined products consumed in that market. We currently ship approximately 12,000 BPD of refined products into the Albuquerque/Moriarty market, which accounts for approximately 15% of the refined products consumed in that market. The common carrier pipelines used by us to serve the Arizona and Albuquerque markets are currently operated at or near capacity and are subject to proration. As a result, the volumes of refined products that we and other shippers have been able to deliver to these markets have been limited. The flow of additional products into El Paso for shipment to Arizona, either as a result of operation of the Longhorn Pipeline or otherwise, could further exacerbate such constraints on our deliveries to Arizona. We could experience future constraints on our ability to deliver our products through the common carrier pipeline to Arizona. Any future constraints on our ability to transport our refined products to Arizona could, if sustained, adversely affect our results of operations and financial condition. As mentioned above, SFPP has announced plans to expand the capacity of its pipeline from El Paso to the Arizona market. This proposed expansion would permit us to ship additional refined products to markets in Arizona, but pipeline tariffs would likely be higher and the expansion would also permit additional shipments by competing suppliers. We cannot presently predict the ultimate effects on us of SFPP’s proposed pipeline expansion.

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The common carrier pipeline we use to serve the Albuquerque market out of El Paso currently operates at or near capacity with resulting limitations on the amount of refined products that we and other shippers can deliver. In addition, HEP leases from Enterprise Products Partners, L.P. a pipeline between Artesia and the Albuquerque vicinity and Bloomfield, New Mexico (the “Leased Pipeline”). The Lease Agreement currently runs through 2007, and HEP has options to renew for three 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.

An additional factor that could affect some of our markets is excess pipeline capacity from the West Coast into our Arizona markets. If refined products become available on the West Coast in excess of demand in that market, additional products could be shipped into our Arizona markets with resulting possible 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. In March 2003, we sold our Iatan crude oil gathering system located in West Texas to Plains All-American Pipeline, L.P. (“Plains”) for a purchase price of $24.0 million in cash. In connection with the transaction, we have entered into a six and a half year agreement with Plains that commits us to transport on that gathering system at an agreed upon tariff any crude oil we purchase in the relevant area of the Iatan system. Crude oil acquired in locations distant from the refinery is exchanged for crude oil that is transportable to the refinery. We also purchase crude oil from producers and other petroleum companies in excess of the needs of our refineries for resale to other purchasers or users of crude oil. See Note 6 to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

We also purchase isobutane, natural gasoline, and other feedstocks to supply the Navajo Refinery. In 2005, approximately 4,000 BPD of isobutane and 4,000 BPD of natural gasoline used in the Navajo Refinery’s operations were purchased from other oil companies in the region and shipped to the Artesia refining facilities on HEP’s 65-mile pipelines running from Lovington to Artesia. We also purchase vacuum gas 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,
	2005			2004			2003
*Navajo Refinery*
Sales of produced refined products:
Gasolines		59	%		59	%		58	%
Diesel fuels		27	%		26	%		23	%
Jet fuels		4	%		5	%		9	%
Asphalt		6	%		6	%		7	%
LPG and other		4	%		4	%		3	%

Total		100	%		100	%		100	%

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

Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, 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 primarily for military use. All asphalt produced at the Navajo Refinery

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and third-party purchased asphalt is marketed through Holly Asphalt Company to governmental entities or contractors. Carbon black oil is sold for further processing, and LPG’s are sold to LPG wholesalers and LPG retailers.

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 3,300 BPD of jet fuel to the DESC in 2005. We have had a military jet fuel supply contract with the United States Government for each of the last 36 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 2005, DESC awarded us contracts for sales of military jet fuel for the period October 1, 2005 through September 30, 2006. Our total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, was approximately 79 million gallons as compared to the total award for the 2004-2005 contract year of approximately 63 million gallons. The loss of 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. In December 2003, we completed a major expansion project at the Navajo Refinery that included the construction of a new gas oil hydrotreater unit and the expansion of the crude refining capacity from 60,000 BPSD to 75,000 BPSD. The total cost of the project was approximately $85 million, excluding capitalized interest.

The gas oil hydrotreater enhances higher value light product yields and expands our ability to produce additional quantities of gasolines meeting the present California Air Resources Board (“CARB”) standards, which were adopted in our Phoenix market for winter months beginning in late 2000, and enables us to meet the recently adopted Environmental Protection Agency (“EPA”) nationwide low-sulfur gasoline requirements that became effective in 2004 for all our gasolines. Additionally, in fiscal 2001 we completed the construction of a new additional sulfur recovery unit, which is currently utilized to enhance sour crude processing capabilities and provide sufficient capacity to recover the additional extracted sulfur resulting from operations of the hydrotreater.

Contemporaneous with the hydrotreater project, we completed necessary modifications to several of the Artesia and Lovington processing units for the Navajo Refinery expansion, which increased crude oil refining capacity from 60,000 BPSD to 75,000 BPSD.

In December 2005, we finished the installation of a refurbished 4,500 BPSD ROSE asphalt unit at the Navajo Refinery at a total cost of $17.1 million. This unit allows us to upgrade asphalt to higher valued gasoline and diesel.

For the 2006 year, our capital budget for the Navajo Refinery totals $46.9 million for various refining improvement projects, not including the clean fuels / expansion project approved in prior years’ capital budgets, as discussed below. Additionally, $5.1 million was approved in the 2006 capital budget for pipeline and other transportation related projects related to the Navajo Refinery operations.

Our clean fuels / expansion strategy for the Navajo Refinery calls for the expansion / conversion of the distillate hydrotreater to gas oil service, the conversion of the gas oil hydrotreater to ULSD service, the expansion of the continuous catalytic reformer, the conversion of the kerosene hydrotreater to naphtha service, and the installation of additional sulfur recovery capacity, which should allow us to produce ULSD by the June 2006 deadline. In addition, we plan to revamp our crude and vacuum units at Artesia and Lovington for improved energy conservation / product cutpoints and to install a 10 million standard cubic feet per day hydrogen plant, which will permit processing of up to 85,000 BPSD of crude. We estimate the total cost to complete the USLD project and expansion of crude oil refining capacity to 85,000 BPSD to be approximately $71 million. In order to avoid additional unit downtime, we plan to phase in the crude expansion starting in the second quarter of 2006 with completion expected in the fourth quarter of 2007. An additional 100 ton per day sulfur recovery unit is planned for startup in the fourth quarter of 2007 at a cost of $25.8 million, which is included in the 2006 capital budget.

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It is anticipated that these projects will also allow the Navajo Refinery, without significant additional investment, to comply with LSG specifications required by the end of 2010.

Woods Cross Refinery

On June 1, 2003 we acquired from ConocoPhillips the Woods Cross Refinery, located near Salt Lake City, Utah, and related assets, including a refined products terminal in Spokane, Washington, and a 50% ownership interest in refined products terminals in Boise and Burley, Idaho for an agreed price of $25.0 million plus inventory less obligations assumed. The purchase also included certain pipelines and other transportation assets used in connection with the refinery, 25 retail service stations located in Utah and Wyoming, and a 10-year exclusive license to market fuels under the Phillips 66 brand in the states of Utah, Wyoming, Idaho and Montana. The total cash purchase price, including expenses and the $2.5 million deposit made in 2002, was $58.3 million. In accounting for the purchase, we recorded inventory of $35.5 million, property, plant and equipment of $25.6 million, intangible assets of $1.6 million and recorded a $4.4 million liability, principally for pension obligations. In August 2003, we sold the 25 retail service stations for $7.0 million, less our prorated share of property taxes and certain transaction expenses, plus $1.8 million for inventories, resulting in net cash proceeds of $8.5 million. We continue to supply the retail stations with fuel from our Woods Cross Refinery under a long-term supply agreement.

The Woods Cross Refinery is being operated by Holly Refining & Marketing Company – Woods Cross, one of our wholly owned subsidiaries. Beginning in January 2005 the crude oil capacity of the refinery was increased from 25,000 BPSD to 26,000 BPSD as a result of continued improvements and advancements at the refinery. The Woods Cross Refinery is located in Woods Cross, Utah and processes regional sweet and Canadian sour crude oils into high value light products.

The following table sets forth information about the Woods Cross Refinery operations, including non-GAAP performance measures about our refinery operations since it was acquired in June 2003. 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 under Part II of this Form 10-K.


	Years Ended December 31,
	2005			2004			2003 ⁽⁸⁾
*Woods Cross Refinery*
Crude Charge (BPD)⁽¹⁾		24,100			23,620			22,540
Refinery production (BPD) ⁽²⁾		25,850			23,730			23,870
Sales of produced refined products (BPD)		26,390			23,520			22,480
Sales of refined products (BPD) ⁽³⁾		27,710			24,160			22,680

Refinery utilization ⁽⁴⁾		92.7	%		94.5	%		90.2	%

Average per produced barrel ⁽⁵⁾
Net sales	$	69.13		$	51.33		$	40.91
Cost of products ⁽⁶⁾		59.51			45.33			34.81

Refinery gross margin		9.62			6.00			6.10
Refinery operating expenses ⁽⁷⁾		4.61			3.92			3.92

Net operating margin	$	5.01		$	2.08		$	2.18


Feedstocks:
Sour crude oil		8	%		7	%		1	%
Sweet crude oil		82	%		88	%		94	%
Other feedstocks and blends		10	%		5	%		5	%

Total		100	%		100	%		100	%


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

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other feedstocks at the refinery.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD).

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

(6)		Subsequent to the formation of HEP, transportation costs billed from HEP are included in cost of products.

(7)		Represents operating expenses of our refinery, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

(8)		We acquired the Woods Cross Refinery on June 1, 2003, and we are reporting amounts for Woods Cross only for periods since the purchase date.

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.

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. Its primary markets include Utah, Idaho and Wyoming where it distributes its products largely through a network of Phillips 66 branded marketers.

The majority of the light refined products produced at the Woods Cross Refinery currently are delivered to customers in the Salt Lake City area. Remaining volumes are shipped via pipelines owned by ChevronTexaco Corporation to numerous terminals, including HEP’s terminals at Boise and Burley, Idaho and Spokane, Washington. The Woods Cross Refinery is one of five refineries located in Utah. We estimate that the four refineries that compete with the Woods Cross Refinery have a combined capacity to process approximately 140,000 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.

Set forth below is information regarding the principal products produced at the Woods Cross Refinery since our acquisition in June 2003.


	Years Ended December 31,
	2005			2004			2003
*Woods Cross Refinery*
Sales of produced refined products:
Gasolines		60	%		59	%		62	%
Diesel fuels		29	%		31	%		26	%
Jet fuels		2	%		1	%		3	%
Fuel oils		7	%		7	%		7	%
LPG and other		2	%		2	%		2	%

Total		100	%		100	%		100	%

For the 2006 year, our capital budget for the Woods Cross Refinery totals $4.7 million for various refining improvement projects, not including the clean fuels project approved in prior years’ capital budgets, as discussed below.

Our clean fuels strategy for the Woods Cross Refinery calls for the construction of a diesel hydrotreater unit, at an estimated cost of $33.7 million, and execution of a long term hydrogen contract that should allow Holly Refining and Marketing – Woods Cross to produce ULSD by the 2006 deadline. This project will also create the infrastructure to allow for another potential project (which at the date of this report has not been included in our capital budget) that would permit us to increase the percentage of sour crude oil runs at the refinery. The Woods Cross Refinery is also required to meet maximum achievable control technology (“MACT”) requirements on its

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FCC flue gas by January 1, 2010 and we plan to desulfurize FCC feed prior to this 2010 date to comply with these requirements as well as the future LSG requirements.

Along with HEP and Enbridge, Inc., we have announced our intent to jointly construct a pipeline to carry crude oil from eastern Utah to the Woods Cross Refinery, with connections to other local refineries. We have not finalized the estimated cost or timing of this project.

Montana Refinery

As announced on March 2, 2006, we have entered into a definitive agreement with Connacher for the sale of the Montana Refinery. The purchase price for the assets including inventories is estimated at approximately $55 million, subject to certain closing adjustments, and includes 1,000,000 shares of Connacher common stock currently valued at approximately $4 million. The consummation of the sale is subject to certain conditions, and we expect the closing to occur on or before April 1, 2006. The amount recorded on our balance sheet at December 31, 2005 for the net assets scheduled to be sold under the definitive agreement is approximately $20 million.

Our petroleum refinery in Great Falls, Montana processes primarily sour Canadian crude oils and primarily serves markets in Montana. Beginning in January 2004 the crude oil capacity of the refinery was increased from 7,000 BPSD to 8,000 BPSD as a result of continued improvements at the refinery.

The following table sets forth information about the Montana Refinery operations, including non-GAAP performance measures for 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 under Part II of this Form 10-K.


	Years Ended December 31,
	2005			2004			2003
*Montana Refinery*
Crude Charge (BPD) ⁽¹⁾		7,890			7,550			6,740
Refinery production (BPD) ⁽²⁾		8,370			8,010			7,350
Sales of produced refined products (BPD)		8,400			7,970			7,150
Sales of refined products (BPD) ⁽³⁾		8,570			8,190			7,620

Refinery utilization ⁽⁴⁾		98.6	%		94.4	%		96.3	%

Average per produced barrel ⁽⁵⁾
Net sales	$	53.74		$	43.10		$	35.80
Cost of products		43.34			35.37			28.17

Refinery gross margin		10.40			7.73			7.63
Refinery operating expenses ⁽⁶⁾		6.72			5.64			5.85

Net operating margin	$	3.68		$	2.09		$	1.78


Feedstocks:
Sour crude oil		93	%		92	%		92	%
Other feedstocks and blends		7	%		8	%		8	%

Total		100	%		100	%		100	%


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

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other feedstocks at the refinery.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD).

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

(6)		Represents operating expenses of our refinery, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

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The Montana Refinery is located on a 56 acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 0.6 million barrels of feedstock and product tankage, extensive asphalt blending / loading facilities, maintenance shops, warehouses and office buildings. The operating units at the Montana facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Great Falls, and units that have been operating as part of the Great Falls facility (with periodic major maintenance) for many years, in some very limited cases since before 1960. The crude oil capacity of the Great Falls facility is 8,000 BPSD and typically processes or blends an additional 300 BPSD of natural gasoline and butane.

The Montana Refinery currently obtains its supply of crude oil from suppliers in Canada via a common carrier pipeline that runs from the Canadian border to the refinery. The Montana Refinery’s principal markets include Great Falls, Helena, Bozeman, Billings and Missoula, Montana. We compete principally with three other Montana refineries. The Montana Refinery is currently meeting the applicable new low sulfur gasoline requirements that became effective in 2004.

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


	Years Ended December 31,
	2005			2004			2003
*Montana Refinery*
Sales of produced refined products:
Gasolines		38	%		41	%		40	%
Diesel fuels		17	%		17	%		15	%
Jet fuels		6	%		5	%		7	%
Asphalt		35	%		33	%		33	%
LPG and other		4	%		4	%		5	%

Total		100	%		100	%		100	%

Because of the pending sale of the Montana Refinery to Connacher, capital spending is limited for 2006. The Montana Refinery is capable, with a minimal additional investment, of producing LSG as required by June 2008 and we have been studying changes necessary to comply by June 2010 with ULSD requirements.

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 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 reduced 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 2 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 and therefore 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”)

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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 revenues to HEP at least equal to specified minimum revenue amounts annually, which are currently $36.7 million under the HEP PTA and $11.8 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. 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 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 LPGs, from West Texas to the Texas/Mexico border near El Paso for further transport into northern Mexico.

Refined Product Terminals:

	•		five refined product terminals (one of which is 50% owned), located in El Paso, Texas; Moriarty, Bloomfield and Albuquerque, 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.

Pipeline Transportation Business

Prior to the initial public offering of HEP on July 13, 2004, certain of our pipelines and terminals were included as part of the pipeline transportation business division. After the offering, the pipelines and terminals that remained became part of the Refining business division. In years prior to the initial public offering of HEP, we developed the pipeline transportation business to generate revenues from unaffiliated parties. The pipeline transportation operations included certain refined product pipelines, the interest in Rio Grande and terminalling agreements that were contributed to HEP along with certain crude oil pipelines that were not contributed to HEP. The following paragraphs provide historic information relating to the assets that were previously included in our pipeline transportation division.

Rio Grande is 70% owned by HEP and 30% owned by BP p.l.c., and serves northern Mexico by transporting LPG’s from a point near Odessa, Texas to a subsidiary of PEMEX at a point near El Paso, Texas. The PEMEX subsidiary then transports the LPG’s to its Mendez terminal near Juarez, Mexico. Deliveries by the joint venture began in April 1997. Prior to the initial public offering of HEP on July 13, 2004, Rio Grande was owned 70% by us and 30% by BP p.l.c. Prior to June 30, 2003, Rio Grande was owned 25% by us and 75% collectively by two parties unaffiliated with us. On June 30, 2003, we purchased an additional 45% interest in Rio Grande, through a wholly-owned subsidiary, adding to the 25% interest that our subsidiary already owned.

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In 1998, we implemented an alliance with FINA, Inc. (“FINA”) to create a comprehensive supply network that can increase substantially the supplies of gasoline and diesel fuel in the West Texas, New Mexico, and Arizona markets to meet expected increasing demand in the future. FINA constructed a 50 mile pipeline that connected an existing FINA pipeline system to our 12-inch pipeline between Orla and El Paso, Texas. In August 1998, FINA began transporting to El Paso, pursuant to a long-term lease of certain capacity of our 12-inch pipeline, gasoline and diesel fuel from its Big Spring, Texas refinery, and we began to realize pipeline rental and terminalling revenues from FINA under these agreements. In August 2000, Alon, succeeded to FINA’s interest in this alliance. Effective from February 2002, Alon transports up to 20,000 BPD to El Paso on this interconnected system.

In the second quarter of fiscal 2000, we acquired certain pipeline transportation and storage assets located in West Texas and New Mexico in an asset exchange with ARCO Pipeline Company. The acquired assets, including 100 miles of pipelines and over 250,000 barrels of tankage, allow us to transport crude oil for unaffiliated companies and increase our ability to access additional crude oil for the Navajo Refinery.

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 $72,000 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 and 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 2006.

Other Investments

Prior to February 28, 2005, we had a 49% interest in MRC Hi-Noon LLC, a joint venture operating retail service stations and convenience stores in Montana, and we accounted for our share of earnings from the joint venture using the equity method. At December 31, 2004, we had a reserve balance of approximately $0.8 million related to the collectability of advances to the joint venture and related accrued interest. On February 28, 2005, we sold our 49% interest to our joint venture partner and agreed to accept partial payment on the advances we previously made to the joint venture. In connection with this transaction, we received $0.8 million, which resulted in a book gain to us of $0.5 million.

Employees and Labor Relations

As of December 31, 2005, we had approximately 881 employees, of which approximately 327 are covered by collective bargaining agreements. During 2005 and early 2006, we successfully negotiated with each of our refinery represented groups terms that will be included in definitive collective bargaining agreements that will 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.

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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 will require capital expenditures for the installation of certain air pollution control devices at our refineries during the next several years. 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, the New Mexico Environment Department and the Montana 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 refineries. The Consent Agreement requires us to make investments at our New Mexico and Montana refineries for the installation of certain state of the art pollution control equipment currently expected to total approximately $15.0 million over a period expected to end in 2010, of which approximately $10.0 million has been expended to date. If the pending sale of the Montana Refinery is consummated, we will not be required to spend approximately $2.0 million (included in the $15.0 million total) for remaining investments at the Montana Refinery under the Consent Agreement.

The EPA and the State of Utah have recently asserted that we have 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 are currently assessing whether it will be feasible to settle the issues presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The EPA and Utah authorities have indicated that any such agreement in the case of the Woods Cross Refinery would likely involve undertakings by us to make specified capital investments and to make changes in operating procedures at the refinery as well as the payment of a penalty. 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. At the date of this report, it is not possible to predict whether we will be able to reach a mutually acceptable agreement with the EPA and Utah environmental authorities, what the terms of any agreement would be, what the outcome would be if the matter were resolved in a lawsuit brought by the EPA and Utah authorities, or what portion of claims asserted by the EPA and the Utah authorities would ultimately be paid by ConocoPhillips.

The CAA may authorize the EPA to require modifications in 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 that is to be allowed in gasoline. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel. 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.

The EPA promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 PPM. The current standard is 500 PPM. As a small business refiner, we may, on a refinery-by-refinery basis, choose to meet the 15 PPM diesel standard in 2006 and extend the interim small refiner gasoline standard by three years (until 2011) or delay the diesel standard by four years (until 2010) and keep the original gasoline sulfur program timing. Our Navajo and Woods Cross refineries plan to meet the diesel sulfur standard in 2006 and take the gasoline extension, while our Montana Refinery plans to keep the original timing for the gasoline sulfur schedule and take the diesel extension.

In June 2004, the EPA issued new regulations that will limit emissions from diesel fuel powered engines used in non-road activities such as mining, construction, agriculture, railroad and marine and will simultaneously limit the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. Although the regulations provide for a timed phase-in of the non-road low sulfur requirements, more time beyond the on-road diesel deadlines to comply, and still more time to comply in the case of small refiners such as us, we plan to meet the ultimate 15 PPM standard for our non-road diesel fuel at the same time we meet the standard for on-road diesel (2006 for the Navajo and Woods Cross refineries, and 2010 for the Montana Refinery). Thus we expect to achieve early compliance for the non-road diesel fuel low sulfur requirements in all three cases.

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We are currently monitoring an EPA initiative on gasoline that would impose further reductions in benzene content, volatility, sulfur, and other parameters. These new requirements, other requirements of the CAA, or other presently existing or future environmental regulations could cause us to expend substantial amounts to permit our refineries to produce products that meet applicable requirements.

We are aware of public concern regarding possible groundwater contamination resulting from the use of MTBE as a source of required oxygen in gasolines sold in specified areas of the country. Gasoline containing a specified amount of oxygen is required by the EPA to be used in those regions that exceed the National Ambient Air Quality Standards for either ozone or carbon monoxide (this requirement is due to be eliminated in 2006 under a mandate contained within the Energy Policy Act of 2005). Meanwhile, the oxygen requirement may be satisfied by adding to gasoline any one of a number of oxygen-containing materials including, among others, MTBE and ethanol. We no longer distribute or market gasolines that contain MTBE.

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

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

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several 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 the Consent Agreement 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.

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We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. 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 or alternative fuel vehicles or an increase in vehicle fuel economy.

In addition, 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 generally results 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.

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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 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 including recent significant 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.

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

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facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.

For addition information on regulations 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.

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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.

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. 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 proration of existing pipelines could impact the supply of refined products to our existing markets, including El Paso, Albuquerque and Phoenix.

The Longhorn Pipeline, which is owned by Longhorn Partners, is a new source of pipeline transportation from Gulf Coast refineries to El Paso. This pipeline is approximately 700 miles and runs from the Houston area of the Gulf Coast to El Paso, utilizing a direct route. Longhorn Partners has announced that it would use the pipeline initially to transport approximately 72,000 BPD of refined products from the Gulf Coast to El Paso and markets served from El Paso, with an ultimate maximum capacity of 225,000 BPD. Since inception of Longhorn Pipeline operations in late 2005, it is our understanding that there have been some limited shipments (substantially under the 72,000 BPD rate) of refined products. Although the Longhorn Pipeline has had very limited impact on us to date, if the Longhorn Pipeline is ever able to operate as has been proposed and significantly increases the volumes of refined products it transports, downward pressure on wholesale refined products margins in El Paso and related markets could result. However, any effects on our markets in Tucson and Phoenix, Arizona and Albuquerque, New Mexico would be expected to be limited in the near-term because current common carrier pipelines from El Paso to these markets are now running at capacity and proration policies of these pipelines allocate only limited capacity to new shippers. Although ChevronTexaco has not announced any plans to expand their common carrier pipeline from El Paso to Albuquerque to address their capacity constraint, SFPP is currently expanding the capacity of its pipeline from El Paso to the Arizona market by between 45,000 and 50,000 BPD. SFPP has announced an expected completion date of April 2006 for this first expansion. Additionally, SFPP announced a further planned expansion of the capacity of this pipeline from El Paso to the Arizona market by 23,000 BPD, with an expected completion date in the summer of 2007. Although our results of operations might be adversely impacted by the Longhorn Pipeline and by the expansions of SFPP’s El Paso-to-Arizona pipeline, we are unable to predict at this time the extent to which we could be negatively affected.

An additional factor that could affect some of our markets is excess pipeline capacity from the West Coast into our Arizona markets after the expansion in 1999 of the pipeline from the West Coast to Phoenix. If refined products become available on the West Coast in excess of demand in that market, additional products may be shipped into our Arizona markets with resulting possible 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.

The common carrier pipelines we use to serve the Arizona and Albuquerque markets are currently operated at or near capacity and are subject to proration. As a result, the volumes of refined products that we and other shippers

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have been able to deliver to these markets have been limited. The flow of additional products into El Paso for shipment to Arizona, either as a result of the Longhorn Pipeline or otherwise, could further exacerbate such constraints on our deliveries to Arizona. No assurances can be given that we will not experience future constraints on our ability to deliver products through the common carrier pipeline to Arizona. Any future constraints on our ability to transport refined products to Arizona could, if sustained, adversely affect our results of operations and financial condition. As mentioned above, SFPP has announced plans to expand the capacity of its pipeline from El Paso to the Arizona market. The proposed expansion would permit us to ship additional refined products to markets in Arizona, but pipeline tariffs would likely be higher and the expansion would also permit additional shipments by competing suppliers. The ultimate effects of SFPP’s proposed pipeline expansion on us cannot presently be estimated.

In the case of the Albuquerque market, the common carrier pipeline we use to serve this market out of El Paso currently operates at or near capacity with resulting limitations on the amount of refined products that we and other shippers can deliver. However, through our relationship with HEP, we have access to pipelines running from near the Navajo Refinery to the Albuquerque vicinity and 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 constraints on 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, please 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 45.0% 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 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 it 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, operations 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.”

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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 have increased, and could increase further. 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 would 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.

Appeals are pending that are expected to affect our lawsuit to recover amounts in dispute in connection with our prior sales of military jet fuel to the United States government.

We have pending in the United States Court of Federal Claims a lawsuit against the Department of Defense relating to claims totaling approximately $299 million with respect to jet fuel sales by two subsidiaries in the years 1982 through 1999. Our claims are similar to claims in a number of other cases also pending in the United States Court of Federal Claims brought by other refining companies concerning military fuel sales. In response to our request, the judge in our case issued in February 2006 an order continuing the stay of our case originally ordered in March 2004. While the stay of our case is in effect we expect that further judicial proceedings in one or more other cases brought by other refining companies may clarify the legal standards that will apply to our case. It is not possible to predict the outcome of further proceedings in our case.

Other legal proceedings that could affect future results are described in Item 3, “Legal Proceedings.”

Terrorist attacks, and the threat of terrorist attacks, 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 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.

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Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

Item 3. Legal Proceedings

We have pending proceedings in the United States Court of Appeals for the District of Columbia Circuit with respect to 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 an SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. In 2004 the appeals court issued its opinion relating principally to the period from 1993 through July 2000, ruling in favor of our positions on most of the disputed issues that concern us, and remanded the case to the FERC for additional consideration of several issues, some of which are involved in our claims. In May 2005, the FERC issued a general policy statement on an issue concerning the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships; this issue was one of the issues in the SFPP case remanded to the FERC by the appeals court, and the position taken in the FERC’s general policy statement is contrary to our position in this case. Decisions by the FERC on certain of the remanded issues were issued in 2005 and early 2006 and these decisions as well as the FERC policy on income taxes are the subject of petitions for review filed by us and certain other refining companies pending before the court of appeals. Rulings by the FERC on certain issues relating to periods after July 2000 have also been the subject of petitions by us and other refining companies for review by the court of appeals. Rulings by the FERC relating principally to the period from 1993 through July 2000 resulted in reparations payments from SFPP to us in 2003 totaling approximately $15.3 million. Because proceedings in the FERC on remand have not been completed and our petitions for review to the court of appeals with respect to the FERC’s orders are pending, it is not possible to determine whether the amount of reparations actually due to us for the period from 1993 through July 2000 will be found to be less than or more than the $15.3 million we received in 2003. Although it is not possible at the date of this report to predict the final outcome of these proceedings, we believe that future proceedings are not likely to result in an obligation for us to repay a significant portion of the reparations payments already received and could result in payment of additional reparations to us. The ultimate amount of reparations payable to us will be determined only after further proceedings in the FERC on issues that have not been finally determined by the FERC, further proceedings in the appeals court with respect to determinations by the FERC, and possibly future petitions by one or more of the parties seeking United States Supreme Court review of issues in the case.

In October 2005, Montana Refining Company (“MRC”) entered into a settlement agreement with the Montana Department of Environmental Quality relating to alleged air quality violations that resulted from a failure in October 2003 of a vapor combustion unit (“VCU”) at MRC’s truck loading rack in Great Falls, Montana and continued operation of the truck loading rack for seven days following the VCU failure while the VCU was being repaired and could not be operated. Under the terms of the settlement agreement a monetary penalty in the amount of approximately $93,000 was paid and MRC will carry out a supplemental environmental project to provide additional environmental benefits in the area where MRC operates.

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presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The EPA and Utah authorities have indicated that any such agreement in the case of the Woods Cross Refinery would likely involve undertakings by us to make specified capital investments and to make changes in operating procedures at the refinery as well as the payment of a penalty. 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. At the date of this report, it is not possible to predict whether we will be able to reach a mutually acceptable agreement with the EPA and Utah environmental authorities, what the terms of any agreement would be, what the outcome would be if the matter were resolved in a lawsuit brought by the EPA and Utah authorities, or what portion of claims asserted by the EPA and the Utah authorities would ultimately be paid by ConocoPhillips.

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 a materially adverse impact on our financial condition, results of operations or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

No matter was submitted to a vote of security holders during the fourth quarter of 2005.

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PART II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

On April 26, 2004, our stock began trading on the New York Stock Exchange under the trading symbol “HOC”. Our stock was formerly traded on the American Stock Exchange under the symbol “HOC”.

The following table sets forth the range of the daily high and low sales prices per share of common stock, dividends paid per share and the trading volume of common stock, as adjusted for the two-for-one stock split in August 2004, for the periods indicated:


							Total
Years ended December 31,	High		Low		Dividends		Volume
2005
First Quarter	$	39.69	$	25.28	$	0.08		16,626,500
Second Quarter	$	47.25	$	32.45	$	0.10		20,785,600
Third Quarter	$	64.87	$	45.55	$	0.10		20,448,400
Fourth Quarter	$	65.45	$	49.74	$	0.10		20,101,500

2004
First Quarter	$	15.99	$	13.51	$	0.065		7,426,800
Second Quarter	$	19.00	$	15.75	$	0.065		7,645,400
Third Quarter	$	25.50	$	18.38	$	0.08		14,491,600
Fourth Quarter	$	28.77	$	22.76	$	0.08		15,597,200

As of February 23, 2006, we had approximately 22,000 stockholders, including beneficial owners holding shares in street name.

We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors. The Credit Agreement limits the payment of dividends. See Note 12 to the Consolidated Financial Statements.

On May 19, 2005, we announced that our Board of Directors authorized the repurchase of up to $100.0 million of our common stock. Repurchases have been 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 the repurchases made under the program which concluded in October 2005.


							Maximum Dollar
					Total Number of		Value of Shares Yet
					Shares Purchased as		to be Purchased as
	Total Number of		Average price Paid		Part of $100 Million		Part of the $100
Period	Shares Purchased		Per Share		Program		Million Program
May 1 – May 31		186,366	$	37.64		186,366	$	92,985,876
June 1 – June 30		517,133	$	42.72		517,133	$	70,894,988
July 1 – July 31		316,758	$	47.37		316,758	$	55,889,259
August 1 – August 31		354,150	$	50.79		354,150	$	37,903,694
September 1 – September 30		352,800	$	59.48		352,800	$	16,918,959
October 1 – October 31		304,000	$	55.65		304,000	$	—

Total		2,031,207	$	49.23		2,031,207

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this annual report on Form 10-K. In this document, the words “we”, “our”, “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

OVERVIEW

We are principally an independent petroleum refiner operating three refineries in Artesia and Lovington, New Mexico (operated as one refinery), Woods Cross, Utah and Great Falls, Montana. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2005, 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 for the year ended December 31, 2005 were $3,212.7 million and our net income for the year ended December 31, 2005 was $167.7 million. Our sales and other revenues and net income for the year ended December 31, 2004 were $2,246.4 million and $83.9 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, 2005 were $2,945.2 million, an increase from $2,100.9 million for the year ended December 31, 2004.

In January 2003 (revised December 2003), FASB issued FIN 46, which we adopted effective December 31, 2003. This interpretation defined 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 losses or income. Through June 30, 2005, our financial statements included the consolidated results of HEP, with the interest we did not own shown as a minority interest in the ownership and earnings. HEP is a VIE as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines discussed below, we have determined that our beneficial variable interest in HEP was less than 50%; and therefore as required by FIN 46, we deconsolidated HEP effective as of 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. All significant intercompany transactions and balances between us and HEP were eliminated through the deconsolidation on July 1, 2005.

On July 8, 2005, we closed on a transaction for HEP to acquire from us two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. The total acquisition price was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. This acquisition was made pursuant to an option to purchase these pipelines we granted to HEP at the time of its initial public offering in July 2004. As a result of this transaction, our ownership interest in HEP has been reduced to 45.0%, including the 2% general partner interest.

In addition to the intermediate feedstock pipelines acquired by HEP, we contributed all of the initial assets of HEP. As these transactions were among entities under common control, the assets were recorded at historical cost by HEP and we did not recognize a gain on the initial contribution or on the intermediate pipelines acquisition. With respect to the intermediate pipelines transaction, this resulted in a payment to us from HEP of $71.9 million in excess of the historical basis of the assets. Because the historical basis is less than the cash received on the transactions, our investment in HEP is a negative investment. The investment balance was eliminated in consolidation until the deconsolidation of HEP from our consolidated financial statements effective July 1, 2005. The net balance of distributions in excess of our investment in HEP was $157.0 million at December 31, 2005.

On February 28, 2005, HEP acquired from Alon and certain of its affiliates over 500 miles of refined products pipelines and two refined products terminals for $120 million in cash and 937,500 HEP Class B subordinated units valued at $24.7 million. As HEP is no longer consolidated in our financial statements effective July 1, 2005, we no longer include in our consolidated financial statements these assets acquired from Alon.

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Balance Sheet Data


	Years Ended December 31,
	2005			2004
	(Dollars in thousands)
Cash, cash equivalents and investments in marketable securities	$	254,842		$	219,265
Working capital	$	198,562		$	148,642
Total assets	$	1,142,900		$	982,713
Total debt, including current maturities and bank borrowings ⁽¹⁾	$	—		$	33,572
Minority interest	$	—		$	157,550
Stockholders’ equity	$	377,351		$	339,916
Total debt to capitalization ratio ⁽²⁾		0.0	%		9.0	%


(1)		Included bank borrowings of HEP of $25.0 million at December 31, 2004.

(2)		The total debt to capitalization ratio is calculated by dividing total debt, including current maturities and borrowings under the revolving credit agreement, by the sum of total debt, including current maturities and borrowings under the revolving credit agreement, and stockholders’ equity.

Other Financial Data


	Years Ended December 31,
	2005			2004			2003
	(In thousands)
Net cash provided by operating activities	$	251,234		$	164,604		$	75,440
Net cash used for investing activities	$	(320,135	)	$	(194,003	)	$	(122,714	)
Net cash provided by financing activities	$	50,505		$	85,169		$	34,698
Capital expenditures	$	106,262		$	37,780		$	74,642
EBITDA⁽¹⁾	$	311,099		$	178,102		$	112,312


(1)		Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense net of interest income, (ii) income tax provision, and (iii) depreciation, 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. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

Our 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 divisions, Refining and HEP. The Refining segment for the years ended December 31, 2004 and 2003 includes the results of operations involving the assets included in HEP prior to the contribution on July 13, 2004. The HEP segment did not have any activity prior to HEP’s formation on July 13, 2004 or subsequent to the deconsolidation effective July 1, 2005.

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	Years Ended December 31,
	2005			2004			2003
	(In thousands)
Sales and other revenues ⁽¹⁾
Refining	$	3,194,767		$	2,234,697		$	1,394,436
HEP		36,034			28,182			—
Corporate and Other		1,772			1,916			9,258
Consolidations and Eliminations		(19,828	)		(18,422	)		(450	)

Consolidated	$	3,212,745		$	2,246,373		$	1,403,244


Income (loss) from operations ⁽¹⁾
Refining	$	301,269		$	175,441		$	82,964
HEP		16,019			12,980			—
Corporate and Other		(49,786	)		(42,907	)		(22,897	)

Consolidated	$	267,502		$	145,514		$	60,067


(1)		The Refining segment includes our principal refinery in Artesia, New Mexico, which is operated in conjunction with refining facilities in Lovington, New Mexico (collectively, the “Navajo Refinery”), the Woods Cross Refinery near Salt Lake City, Utah and our refinery in Great Falls, Montana, as well as our asphalt operations. The Refining segment involves the purchase and refining of crude oil and wholesale marketing of refined products such as gasoline, diesel fuel and jet fuel. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Montana, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil and intermediate product pipelines prior to July 8, 2005 (see Note 2 to our consolidated financial statements), that we owned and operated in conjunction with our refining operations as part of the supply networks of the refineries. In February 2005, we acquired the remaining 51% interest in our asphalt joint venture from the other partner; subsequent to the purchase, we are including the operations of NK Asphalt Partners in our consolidated financial statements. NK Asphalt Partners, dba Holly Asphalt Company, manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and California and is included in the refining segment. The cost of pipeline transportation and terminal services provided by HEP is also included in the Refining segment. The HEP segment includes all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of its pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain States. Revenues of the HEP segment were earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in the Rio Grande which provides petroleum products transportation. Results of operations involving the assets included in the HEP segment prior to July 13, 2004 are included in the Refining segment for reporting purposes. Our operations not included in the Refining or HEP segment are included in Corporate and Other, which includes costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations amount includes the elimination of the revenues and costs associated with the pipeline transportation services provided to us by HEP.

Refining Operating Data

Our refinery operations include the Navajo Refinery, the Woods Cross Refinery and the Montana 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 under Part II of this Form 10-K.


	Years Ended December 31,
	2005			2004			2003 ⁽⁸⁾
*Consolidated*
Crude Charge (BPD) ⁽¹⁾		103,840			102,230			76,040
Refinery production (BPD) ⁽²⁾		114,410			111,070			85,030
Sales of produced refined products (BPD)		114,900			110,370			82,900
Sales of refined products (BPD) ⁽³⁾		125,680			118,760			95,420

Refinery utilization ⁽⁴⁾		95.3	%		94.7	%		93.2	%

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	Years Ended December 31,
	2005		2004		2003 ⁽⁸⁾
*Consolidated*
Average per produced barrel ⁽⁵⁾
Net sales	$	67.99	$	50.80	$	38.99
Cost of products ⁽⁶⁾		55.53		41.70		31.76

Refinery gross margin		12.46		9.10		7.23
Refinery operating expenses ⁽⁷⁾		4.30		3.53		3.58

Net operating margin	$	8.16	$	5.57	$	3.65


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

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other feedstocks at our refineries.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD).

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

(6)		Subsequent to the formation of HEP, transportation costs billed from HEP are included in cost of products.

(7)		Represents operating expenses of refineries, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

(8)		We acquired the Woods Cross Refinery on June 1, 2003, and we are reporting amounts for Woods Cross only for periods since the purchase date.

Results of Operations – Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Summary

Net income for the year ended December 31, 2005 was $167.7 million ($5.30 per diluted share) compared to net income of $83.9 million ($2.61 diluted share) for the year ended December 31, 2004. Earnings for 2005 as compared to 2004 increased 100% or $83.8 million principally due to high refined product margins experienced in 2005. Additionally impacting earnings favorably were increased refinery production volumes, offset by higher refinery operating costs and expenses. In 2004, we received 100% of the benefit of the refined product pipelines and terminals contributed to HEP prior to its initial public offering in July 2004, whereas from July 2004 through 2005, approximately half of the income from HEP’s refined product pipelines and terminals has been attributable to other owners. Overall refinery production levels increased 3% to a total production level of 114,410 BPD in 2005 due to increased production at all refineries. Company-wide refinery margins were $12.46 per barrel in 2005 compared to margins of $9.10 per barrel in 2004.

Sales and Other Revenues

Sales and other revenues increased 43% from $2,246.4 million in 2004 to $3,212.7 million in 2005 due principally to higher refined product sales prices, and to a lesser degree, increased volumes sold at our refineries. The average sales price we received per produced barrel sold increased 34% from $50.80 in 2004 to $67.99 in 2005. The total volume of refined products we sold increased 6% in 2005 as compared to 2004. Additionally impacting sales were increases in the current year due to the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements following our February 2005 purchase of the other partner’s interest, and the inclusion of revenues from HEP’s assets acquired from Alon for the period March through June 2005.

Cost of Products Sold

Cost of products sold increased 44% from $1,836.0 million in 2004 to $2,636.6 million in 2005 due principally to higher costs of crude oil, and to a lesser degree, increased volumes sold. The average price we paid per barrel of crude oil purchased increased 33% from $41.70 in 2004 to $55.53 in 2005. Additionally impacting cost of sales were increases in the current year due to the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements.

We recognized $4.1 million and $4.9 million in income in 2005 and 2004, respectively, resulting from the liquidations of certain last-in, first-out (“LIFO”) inventory quantities that were carried at lower costs compared to

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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, which was recorded as a decrease in cost of products sold.

Gross Refinery Margins

The gross refining margin per produced barrel increased 37% from $9.10 in 2004 to $12.46 in 2005. Gross refinery margin does not include the effect 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 statement of prices of refined products sold and cost of products purchased.

Operating Expenses

Operating expenses increased 23% from $172.5 million in 2004 to $212.7 million in 2005 due to the higher production levels, increased utility and catalyst costs, operating costs associated with the assets HEP acquired from Alon for the period March to June 2005 prior to the HEP deconsolidation and the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements, while reduced by the operating costs of HEP in the 2005 third and fourth quarters which are no longer consolidated in the Company’s results. The increase in utility costs was mainly due to price increases during 2005 for purchased natural gas.

General and Administrative Expenses

General and administrative expenses increased 1% from $51.2 million in 2004 to $51.7 million in 2005 due primarily to an increase in non-share based incentive compensation, offset by a decrease in share-based compensation expense and reduced legal fees for 2005 as compared to 2004.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 8% from $40.5 million in 2004 to $43.8 million in 2005 due to depreciation on the assets HEP acquired from Alon for the period March to June 2005, the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated statements and increased depreciation and amortization on other capital assets placed in service in 2004 and 2005. These factors were partially offset by the absence of depreciation on HEP’s assets for the third and fourth quarters of 2005 after the deconsolidation of HEP effective July 1, 2005.

Equity in Earnings of HEP

As part of the deconsolidation of HEP effective July 1, 2005, we now show equity in earnings in HEP for our ownership percentage of HEP, currently 45.0%, including any incentive distributions paid with respect to our general partner interest. Equity in earnings of HEP in 2005 was $6.5 million, which represents our 45.0% of HEP’s earnings for the last six months of 2005. There was no equity in earnings of HEP for 2004 as HEP was a consolidated subsidiary from its commencement of operations.

Equity in Earnings of Joint Ventures and Minority Interests
Equity in earnings of joint ventures in 2005 included a loss of $0.7 million from our interest in NK Asphalt joint venture for the period prior to the increase in our ownership to 100% in February 2005. Minority interests in income of partnerships in 2005 was a reduction in income of $6.7 million which represented the minority interest partners’ 52.1% ownership share of HEP’s income prior to July 2005 (49% prior to HEP’s asset acquisition from Alon on February 28, 2005). As of July 1, 2005, minority interests are no longer being recognized due to the deconsolidation of HEP. Equity in earnings of joint ventures in 2004 included a loss of $0.1 million from our interest in NK Asphalt joint venture. Minority interests in income of partnerships in 2004 resulted in a reduction of income of $7.6 million. This represented the minority interest partners’ 49% ownership of HEP (subsequent to HEP’s July 2004 initial public offering) and the minority owner’s 30% ownership share of the Rio Grande joint venture’s income (prior to HEP’s initial public offering).

Interest Income

Interest income for 2005 was $6.9 million compared to $4.4 million for 2004. Interest income in 2005 represents interest earned on our investable funds resulting from the receipt of proceeds from the initial public offering of HEP, sale of intermediate pipelines to HEP and internally generated cash flows. The interest income in 2004 resulted from the $2.2 million accrued interest received with $25.0 million of principal from Longhorn Partners Pipeline, L.P. on July 1, 2004 and the interest earned on the proceeds from the initial public offering of HEP in July 2004.

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Interest Expense

Interest expense was $5.1 million for 2005 as compared to $3.5 million for 2004. The increase for 2005 as compared to 2004 was principally due to higher interest costs associated with the 6.25% senior notes of HEP due 2015 (“HEP Senior Notes”) through June 30, 2005 prior to deconsolidation.

Income Taxes

Income taxes increased 86% from $54.6 million in 2004 to $101.4 million in 2005 due principally to the higher earnings during 2005 as compared to 2004. The effective tax rate for 2005 was 37.8%, as compared to 39.4% for 2004. Our effective tax rate decreased in 2005 as compared to 2004 primarily due to the impact of the domestic production activities deduction enacted under the American Jobs Creation Act of 2004. In 2005, the current tax provision increased approximately $15.0 million due to the tax gain associated with the acquisition by HEP of the intermediate feedstock pipelines, an amount which was partially offset by the approximately $10.0 million reduction in current tax resulting from the immediate deduction allowed for 75% of certain costs paid or incurred in complying with the ULSD standards. The high current tax provision in 2004 reflects approximately $26.0 million associated with the tax gain on assets contributed upon the formation of HEP in July 2004.

Cumulative Effect of Accounting Change

With the adoption of Statement of Financial Accounting Standards (“SFAS”) 123 (revised), we recorded a cumulative effect of a change in accounting principle relating to our performance units, due to the initial effect of measuring these awards at fair value, where previously they were measured at intrinsic value. The total cumulative effect of this change in accounting principle recorded upon adoption was a gain of approximately $699,000, net of a deferred tax expense of approximately $426,000.

Results of Operations – Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Summary

Net income for the year ended December 31, 2004 was $83.9 million ($2.61 per diluted share), an increase of $37.8 million from net income of $46.1 million ($1.44 per diluted share) for the year ended December 31, 2003. The year ended December 31, 2003 benefited from a $15.3 million reparations payment received and a one time pre-tax gain of $16.2 million associated with the sale of certain pipeline assets. The combined effect of the reparations payment and gain on the sale was a $19.4 million increase in after-tax income and represented $0.61 per diluted share.

The $37.8 million increase in net income in 2004 as compared to 2003 was due mainly to improved refined product margins and higher volumes from the inclusion of a full year of operations of our Woods Cross Refinery acquired in June 2003 and the completion of the expansion of our Navajo Refinery in December 2003. In addition to the industry wide improvements in refined product margins, we also benefited in 2004 from the new gas oil hydrotreater at the Navajo Refinery that was completed in 2003, which enhances higher value light product yields and allows us to process virtually all sour crude oil. These positive factors for 2004 were offset by the reparations payment received and the gain on sale of pipeline assets in 2003, and in 2004 increased operating expenses, principally due to the inclusion of a full year of operations of our Woods Cross Refinery, and increased selling, general and administrative expenses, principally due to additional employee compensation resulting from increased incentive compensation and additional personnel. Additionally, our earnings were reduced by $5.6 million for the public’s 49% share of HEP’s earnings after HEP’s initial public offering in July 2004.

Sales and Other Revenues

Sales and other revenues increased 60% from $1,403.2 million in 2003 to $2,246.4 million in 2004 due to increased refined product prices, the higher volumes at the Navajo Refinery, and the inclusion of a full year of operations at our Woods Cross Refinery. The average sales price we received per produced barrel sold increased 30% from $38.99 in 2003 to $50.80 in 2004. The total volume of refined products we sold increased 25% in 2004 as compared to 2003.

Cost of Products Sold

Cost of products sold increased 59% from $1,155.9 million in 2003 to $1,836.0 million in 2004 due to higher costs of crude oil, the higher volumes at the Navajo Refinery, and the inclusion of a full year of operations at our Woods Cross Refinery. The average price we paid per barrel of crude oil purchased increased 31% from $31.76 in 2003 to $41.70 in 2004.

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We recognized $4.9 million in income in 2004 resulting from the liquidations of certain LIFO inventory quantities that were carried at lower costs compared to current costs.

Gross Refinery Margins

The gross refining margin per produced barrel increased 26% from $7.23 in 2003 to $9.10 in 2004. In comparing 2004 to 2003, most of our overall gross refinery margin improvement was due to increased margins at our Navajo Refinery of 37%, partially resulting from the new gas oil hydrotreater at the Navajo refinery that was completed in 2003. Gross refinery margin does not include the effect 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 statement of prices of refined products sold and costs of crude oil purchased.

Operating Expenses

Operating expenses increased 28% from $134.3 million in 2003 to $172.5 million in 2004 due primarily to the inclusion of a full year of operations of the Woods Cross Refinery, higher utility costs, increases in maintenance costs, the addition of personnel in 2004 and stock based compensation grants made in 2004.

General and Administrative Expenses

General and administrative expenses increased 62% from $31.6 million in 2003 to $51.2 million in 2004 due primarily to additional employee compensation expense of $18.4 million, principally due to additional employee compensation resulting from increased incentive compensation and additional personnel.

Depreciation, Depletion and Amortization Expense

Depreciation, depletion and amortization expense increased 12% from $36.3 million in 2003 to $40.5 million in 2004 due to the Woods Cross Refinery, the large capital program at the Navajo Refinery and the inclusion of the Rio Grande joint venture for the full year in our 2004 consolidated financial statements.

Equity in Earnings of Joint Ventures and Minority Interest

Equity in earnings of joint ventures in 2004 included a loss of $0.1 million from our 49% interest in the NK Asphalt joint venture and a loss of $0.2 million from our 49% interest in the MRC Hi-Noon LLC joint venture. Equity in earnings of joint ventures in 2003 included $1.0 million from our interest in the NK Asphalt joint venture and $0.5 million from our 25% interest in the Rio Grande joint venture. Since our acquisition of an additional 45% interest in the Rio Grande joint venture on June 30, 2003, we consolidate the results of the Rio Grande joint venture in our financial statements.

Minority interest in income of partnerships was $7.6 million in 2004 and $0.8 million in 2003, which is a reduction in income, by virtue of the minority partners’ ownership share. The minority interest in income of partnerships for 2004 represents the minority interest partner’s 49% ownership share of HEP (subsequent to its initial public offering) and the 30% ownership of the Rio Grande joint venture’s income (prior to HEP’s initial public offering). The minority interest income of partnerships for 2003 represents the minority interest partner’s 30% ownership share of the Rio Grande joint venture’s income.

Gain on Sales of Assets

The gain on sale of assets of $15.8 million in 2003 includes a $16.2 million gain on sale of pipeline assets and $0.4 million loss on sale of Woods Cross retail assets.

Interest Income

Interest income for 2004 was $4.4 million as compared to $0.5 million for 2003. The increase of $3.9 million was due principally to the $2.2 million interest earned on the receivable from Longhorn Partners. On July 1, 2004, we received $27.2 million from Longhorn Partners which represented $25.0 principal plus $2.2 million in interest on the Longhorn Partners note and resulted in a termination of our prepaid transportation rights under the November 2002 settlement agreement with Longhorn Partners. Additionally, the increase in interest income was due to higher levels of investable funds resulting from the receipt of proceeds from the initial public offering of HEP and internally generated cash flows.

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Interest Expense

Interest expense, net of capitalized interest, was $3.5 million for 2004 as compared to $2.1 million for 2003. The $1.4 million increase was due to higher borrowings made under our credit agreement during the first half of 2004 and borrowings made under the HEP credit agreement in the last half of 2004 in addition to the fact that in 2003 we capitalized $1.2 million of interest costs relating to significant construction projects at the Navajo Refinery.

Reparations Payment Received

The $15.3 million reparations payment received in 2003 represents amounts we received from SFPP under an order by the FERC relating to tariffs we paid in prior years for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona.

Income Taxes

Income taxes increased by 93% from $28.3 million in 2003 to $54.6 million in 2004 due to the $64.1 million increase in net income before income taxes. The effective tax rate for 2004 was 39.4% as compared to 38.1% for 2003. The higher effective tax rate was due primarily to an increase in estimated state income taxes. The current income tax provision was $80.0 million for 2004. This amount related both to taxes on income before income taxes and to approximately $26.0 million associated with the tax gain on assets contributed upon the formation of HEP in July 2004. The large deferred tax expense in 2003 was principally due to increased depreciation for tax purposes on capital projects and major refinery maintenance.

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”) and auction rate securities (“ARS”). Although VRDN and ARS 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. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of December 31, 2005, we had cash and cash equivalents of $49.1 million, marketable securities with maturities under one year of $190.0 million and marketable securities with maturities greater than one year, but less than two years, of $15.8 million.

Cash and cash equivalents decreased by $18.4 million during 2005. The cash used for investing activities of $339.3 million exceeded the combination of the cash generated from operating activities of $242.3 million and the cash flow provided by financing activities of $78.6 million. Working capital increased during 2005 by $49.9 million.

We hold 7,000,000 subordinated units of HEP. Our rights as holder of subordinated units to receive distributions of cash from HEP are subordinated to the rights of common unit holders to receive such distributions. Until the February 28, 2005 Alon asset acquisition as discussed below, we owned a 51% interest in HEP, consisting of a 2% general partner interest and a 49% subordinated limited partner interest. The initial public offering represented the sale by us of a 49% interest in HEP. After the sale of our intermediate pipelines to HEP on July 8, 2005, as discussed below, our ownership interest in HEP was reduced to 45.0%, including our 2% general partner interest.

On July 1, 2004, we entered into a new $175 million secured revolving credit facility with Bank of America as administrative agent and a lender, with a term of four years and an option to increase it to $225 million subject to certain conditions. The credit facility may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes. As of December 31, 2005, we had letters of credit outstanding under our revolving credit facility of $2.3 million and had no borrowings outstanding. We were in compliance with

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all covenants at December 31, 2005. Additionally, a credit facility is in place for the benefit of HEP, as described below.

On November 7, 2005, we announced that our Board of Directors authorized the repurchase of up to $200.0 million of our 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 2005, we repurchased 493,800 shares at a cost of approximately $30.0 million or an average of $60.66 per share under this repurchase initiative. Additionally in 2005, we repurchased 2,031,207 shares at a cost of approximately $100.0 million or an average of $49.23 per share under an earlier 2005 repurchase initiative.

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 our common stock under our $200.0 million 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.

Sale of Intermediate Pipelines to HEP

On July 8, 2005, we closed on a transaction in which HEP acquired our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. The total acquisition price was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. HEP financed the approximately $77.7 million cash portion of the consideration for the intermediate pipelines with the proceeds raised from the private sale of 1.1 million of its common units for $45.1 million to a limited number of institutional investors, which closed simultaneously with the acquisition, and the offering of an additional $35.0 million in principal amount of HEP Senior Notes completed in June 2005 (discussed below). This acquisition was made pursuant to an option to purchase these pipelines we granted to HEP at the time of HEP’s initial public offering in July 2004. We have agreed to a 15-year pipelines agreement with a minimum annual volume commitment of 72,000 BPD on the pipelines, which will result in annual revenues to HEP of approximately $11.8 million (this amount will adjust upward based on the producer price index). In addition, we have agreed to indemnify HEP, subject to certain limits, for any environmental noncompliance and remediation liabilities occurring or existing prior to the closing date. As a result of this transaction, our ownership interest in HEP has been reduced to 45.0%, including our 2% general partner interest.

Other HEP Activity

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. Beginning with the third quarter of 2004, we consolidated the results of HEP with minority interest treatment for the common units. As we reported HEP as a consolidated subsidiary from July 13, 2004 through June 30, 2005, the following highlights the major activities of HEP.

In connection with the initial public offering of HEP on July 13, 2004, we entered into a 15-year pipelines and terminals agreement with HEP under which we agreed generally to transport or terminal volumes on certain of HEP’s initial facilities that will result in revenues that will equal or exceed a specified minimum revenue amount annually (which currently is at $36.7 million and will adjust upward based on the producer price index) over the term of the agreement. Additionally, we agreed to indemnify HEP up to an aggregate amount of $15 million for ten years for any environmental noncompliance and remediation liabilities associated with the assets transferred to HEP and occurring or existing prior to the date of the initial public offering.

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HEP’s Alon Transaction

On February 28, 2005, HEP closed its acquisition from Alon of four refined products pipelines aggregating approximately 500 miles, an associated tank farm and two refined products terminals with aggregate storage capacity of approximately 347,000 barrels. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s 65,000 BPSD capacity refinery in Big Spring, Texas. Following the closing of this transaction, we owned 47.9% of HEP including the 2% general partner interest and other investors in HEP owned 52.1%. The total consideration paid by HEP for these pipeline and terminal assets was $120 million in cash and 937,500 Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units in five years. HEP financed the Alon transaction through a private offering of $150 million principal amount of the HEP Senior Notes (discussed below). HEP used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction and used the balance to repay $30 million of outstanding indebtedness under its credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. HEP amended its credit agreement prior to the Alon acquisition and note offering to allow for these events as well as to amend certain of the restrictive covenants. In connection with the Alon transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon.

HEP’s Credit Facility

On July 7, 2004, one of our affiliates, Holly Energy Partners — Operating, L.P., a wholly owned subsidiary of HEP, entered into a four-year $100 million credit facility with Union Bank of California, as administrative agent and a lender, in conjunction with the initial public offering, with an option to increase the amount to $175 million under certain conditions. HEP amended the credit facility effective February 28, 2005 to allow for the closing of the Alon transaction and the related HEP Senior Notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from the HEP Senior Notes offering, HEP repaid $30 million of outstanding indebtedness under the credit facility, including $5 million drawn shortly before the closing of the Alon transaction. The credit facility was amended effective July 8, 2005 to allow for the closing of the Holly intermediate pipelines transaction as well as to amend certain of the restrictive covenants. As of December 31, 2004, $25.0 million was drawn under the facility and was included in our consolidated balance sheet at that date. As of December 31, 2005, HEP did not have any borrowings outstanding under the facility.

HEP’s Senior Notes Due 2015

HEP financed the Alon transaction through its private offering on February 28, 2005 of $150 million principal amount of HEP Senior Notes. HEP used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under its credit facility, including $5 million drawn shortly before the closing of the Alon transaction. HEP partially financed the purchase of our intermediate feedstock pipelines on July 8, 2005 through the offering in June 2005 of an additional $35.0 million in principal of HEP’s Senior Notes.

The HEP Senior Notes mature on March 1, 2015 and bear interest at 6.25%. The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes.

The $185 million HEP Senior Notes are not recorded on our accompanying consolidated balance sheet at December 31, 2005 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 controlling partner to the extent it makes any payment in satisfaction of $35 million of the principal amount of the HEP Senior Notes.

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Cash Flows — Operating Activities

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Net cash flows provided by operating activities amounted to $251.2 million in 2005 compared to $164.6 million in 2004, an increase of $86.6 million. Net income in 2005 was $167.7 million, an increase of $83.8 million from net income of $83.9 million 2004. The non-cash items of depreciation and amortization, deferred taxes, minority interests and equity-based compensation increased by $20.8 million for the year ended December 31, 2005 from the year ended December 31, 2004. Distributions in excess of equity in earnings of Holly Energy Partners and joint ventures decreased by $1.7 million for the year ended December 31, 2005 from the year ended December 31, 2004. Working capital items increased cash flows by $35.9 million in 2005, as compared to an increase of $24.5 million in 2004. Changes in accounts receivable and accounts payable were the primary causes of the increase in cash flows from working capital items for 2005 as compared to 2004. For 2005, accounts receivable increased $128.3 million and accounts payable increased $143.3 million, as compared to 2004 when accounts receivable increased $97.4 million and accounts payable increased $99.0 million. These increases were principally due to increases in prices for refined products and crude oil. Additionally, positively impacting cash provided by operating activities in 2004 was the $25.0 million (excluding interest) returned to us by Longhorn Partners under a prepaid transportation agreement.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Net cash provided by operating activities amounted to $164.6 million in 2004 compared to $75.4 million in 2003. Comparing 2004 to 2003, the $89.2 million increase in cash provided by operations was primarily the result of a $37.8 million increase in net income (including the effect of the pre-tax gain on sale of assets). Additionally, positively impacting cash provided by operating activities in 2004 as compared to 2003 were greater increases in accounts payable of $34.8 million and net income taxes receivable of $8.6 million, a decrease in inventories in 2004 as compared to an increase in inventories in 2003 resulting in a net decrease of $24.8 million, the refund of $25.0 million returned to us by Longhorn Partners under a prepaid transportation agreement, a decrease in turnaround expenditures incurred of $17.6 million, the reduction in 2003 of the non-cash gain on sale of assets and an increase in distributions in excess of equity in earnings of joint ventures of $1.2 million. These increases in cash flow were partially offset by significant items decreasing cash flow, when comparing 2004 to 2003, including a greater increase in accounts receivable of $61.9 million, an increase in prepayments and other in 2004 as compared to a decrease in 2003 resulting in a net increase of $5.5 million and a decrease of $45.7 million in deferred taxes.

Cash Flows — Investing Activities and Capital Projects

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Net cash flows used for investing activities were $320.1 million for 2005 and $194.0 million for 2004, a net change of $126.1 million. Cash expenditures for property, plant and equipment for 2005 totaled $106.3 million as compared to $37.8 million for 2004. 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 the sale or maturity of marketable securities during 2005. We also invested $271.7 million in marketable securities and received proceeds of $119.0 million from the sale or maturity of marketable securities during 2004. Also, in 2004, we invested $3.3 million in joint ventures.

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Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Cash flows used for investing activities were $194.0 million for 2004 compared to $122.7 million for 2003. Cash expenditures for property, plant and equipment for 2004 totaled $37.8 million as compared to $74.6 million in 2003. Most of the 2003 expenditures were for the hydrotreater and expansion projects at the Navajo Refinery. During 2004, we invested $271.7 million in marketable securities and received proceeds of $119.0 million from the sale or maturity of a portion of those marketable securities. Our net cash flows provided by investing activities in 2003 included $24.0 million in proceeds from the sale of a crude oil gathering pipeline system located in West Texas, a cash outlay of $55.8 million in 2003 (plus a $2.5 million deposit made in 2002) for the purchase of the Woods Cross Refinery on June 1, 2003 and $28.7 million for the purchase of an additional 45% interest in the Rio Grande joint venture. The acquisition is shown in the statement of cash flows net of the $7.3 million of cash owned by the Rio Grande Pipeline Company at the time of our acquisition. Our net cash flows used for investing activities were reduced in 2003 by $8.5 million in proceeds (including inventory sold) from the sale of retail assets purchased as part of the Woods Cross Refinery acquisition.

Planned Capital Expenditures

Each year our Board of Directors approves capital projects that our management is authorized to undertake in our annual capital budget. 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 2006 is approximately $62.2 million, not including the capital projects approved in prior years, mainly our ULSD and expansion projects at the Navajo and Woods Cross refineries, as described below. The 2006 capital budget is comprised of $46.9 million for refining improvement projects for the Navajo Refinery, $4.7 million for projects at the Woods Cross Refinery, $5.1 million for transportation projects, $0.4 million for marketing related projects, $0.7 million for asphalt plant projects and $4.4 million for information technology and other miscellaneous projects. In 2006 we expect to expend approximately $100.0 million on currently approved capital projects, which amount primarily consists of certain carryovers of capital projects from previous years, less carryovers to 2007 of certain of the currently approved capital projects.

Our clean fuels / expansion strategy for the Navajo Refinery calls for the expansion / conversion of the distillate hydrotreater to gas oil service, the conversion of the gas oil hydrotreater to ULSD service, the expansion of the continuous catalytic reformer, the conversion of the kerosene hydrotreater to naphtha service, and the installation of additional sulfur recovery capacity, which should allow us to produce ULSD by the June 2006 deadline. In addition, we plan to revamp our crude and vacuum units at Artesia and Lovington for improved energy conservation / product cutpoints and to install a 10 million standard cubic feet per day hydrogen plant, which will permit processing of up to 85,000 BPSD of crude. We estimate the total cost to complete the USLD project and expansion of crude oil refining capacity to 85,000 BPSD to be approximately $71 million, which was approved in prior years’ capital budgets. In order to avoid additional unit downtime, we plan to phase in the crude expansion starting in the second quarter of 2006 with completion expected in the fourth quarter of 2007. An additional 100 ton per day sulfur recovery unit is planned for startup in the fourth quarter of 2007 at a cost of $25.8 million, which amount is included in the 2006 capital budget. It is anticipated that these projects will also allow the Navajo Refinery, without significant additional investment, to comply with LSG specifications required by the end of 2010.

Our clean fuels strategy for the Woods Cross Refinery calls for the construction of a diesel hydrotreater unit, at an estimated cost of $33.7 million, which was approved in prior years’ capital budgets, and execution of a long term hydrogen contract that should allow Holly Refining and Marketing – Woods Cross to produce ULSD by the June 2006 deadline. This project will also create the infrastructure to allow for another potential project (which at the date of this report has not been included in our capital budget) that would permit us to increase the percentage of sour crude oil runs at the refinery. The Woods Cross Refinery is also required to meet MACT requirements on its FCC flue gas by January 1, 2010 and we plan to desulfurize FCC feed prior to this 2010 date to comply with these requirements as well as the future LSG requirements.

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The Montana Refinery is capable, with a minimal additional investment, of producing LSG as required by June 2008 and we are studying changes necessary to comply by June 2010 with ULSD requirements.

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/or incur additional operating costs to meet applicable requirements.

On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. Among other things, the Act creates tax incentives for small business refiners preparing to produce ULSD. The 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 present value of tax savings that we will derive from capital expenditures associated with ULSD projects to be in excess of $22.0 million, representing the difference between the value of allowed deductions and credits under the Act as compared to the value of depreciating investments over normal depreciable lives.

Cash Flows — Financing Activities

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Net cash flows provided by financing activities were $50.5 million for 2005, as compared to $85.2 million for 2004, a decrease of $34.7 million. 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. In 2004, we received $142.0 million in net proceeds from the HEP initial public offering. During 2004 we repaid in full our borrowings under our credit facility of $50.0 million, and during 2004 HEP borrowed $25.0 million under their credit facility. Additionally, during 2004, we made a scheduled repayment of long-term debt of $8.6 million, paid $8.3 million in dividends, repurchased treasury stock for $15.3 million, received $4.7 million for common stock issued upon the exercise of options, made distributions of $3.2 million to the minority interest partner of Rio Grande, incurred debt issuance costs of $3.6 million related to our credit facility and HEP’s financing, made distributions of $3.1 million to the minority interest holders of HEP and recognized $5.6 million in excess tax benefits on our equity based compensation.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Cash flows provided by financing activities were $85.2 million in 2004, as compared to $34.7 million in 2003. In 2004, we received $142.0 million in net proceeds from the HEP initial public offering and repaid in full our borrowings under our credit facility of $50.0 million; however, HEP borrowed $25.0 million under their credit facility, resulting in a net decrease in borrowings under our credit facilities in 2004 of $25.0 million. Additionally, during 2004, we made a scheduled repayment of long-term debt of $8.6 million, paid $8.3 million in dividends, purchased treasury stock for $15.3 million, received $4.7 million for common stock issued upon exercise of stock options, made distributions of $3.2 million to the minority interest partner of Rio Grande, made distributions of $3.1 million to the minority interest holders of HEP and incurred $3.6 million of debt issuance costs related to our credit facility and HEP’s financing. In 2003, we borrowed $50.0 million under our credit agreement as partial funding for

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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. 123 (revised) “Share-Based Payment“
In December 2004, the FASB issued SFAS No. 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide-range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. This standard was to become effective for us for the first interim period beginning after June 15, 2005; however in April 2005, the SEC allowed for a delay in the implementation of this standard, with the result that we are not required to adopt this standard until our 2006 year. SFAS No. 123 (revised) allows for either modified prospective recognition of compensation expense or modified retrospective recognition, which may be back to the original issuance of SFAS No. 123 (revised) or only to interim periods in the year of adoption. We elected early adoption of this standard on July 1, 2005 based on modified retrospective application with early application under SFAS No. 123 (revised) to prior quarters in the current year (see Note 4 to our consolidated financial statements).

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4"
In December 2004, the FASB issued SFAS No. 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4.” This amendment requires abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) to be recognized as current-period charges. This standard also requires that the allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. This standard is effective for fiscal years beginning after June 15, 2005. We will adopt the standard effective for our 2006 year. We do not anticipate the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows.

SFAS No. 154 “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3"
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and SFAS No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principle and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This standard becomes effective for fiscal years beginning after December 15, 2005. The impact of this standard will be determined upon the issuance of new standards or our voluntary change in an accounting principle.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations"
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under SFAS No. 143. FIN 47 is effective for fiscal years ending after December 15, 2005.

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We adopted the standard effective as of December 31, 2005. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

Emerging Issues Task Force consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty"
The Emerging Issues Task Force reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it in September 2005. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The consensus in this Issue is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. We have certain crude oil transactions that are accounted for on a net cost basis. We do not believe that our revenues or cost of sales will be materially impacted by applying the Issue’s consensus.

RISK MANAGEMENT

We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe 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 periodically utilize 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 $535,000 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 recent high 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

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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.

In December 2002, we entered into cash flow hedges relating to certain forecasted transactions to buy crude oil and sell gasoline in March 2003. The purpose of the hedges was to help protect us from the risk that the refinery margin would decline with respect to the hedged crude oil and refined products. To affect the hedges, we entered into gasoline and crude oil futures transactions. Gains and losses reported under accumulated other comprehensive income were reclassified into income when the forecasted transactions occurred. During 2002, we marked the value of the outstanding hedges to fair value in accordance with SFAS No. 133 and included $0.1 million of income in comprehensive income. In March 2003, as the forecasted transactions occurred, we reclassified $0.1 million of actual losses from comprehensive income to cost of sales. The ineffective portion of the hedges resulted in a less than $0.1 million gain that was also included in cost of sales.

HEP entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of its HEP Senior Notes from a fixed rate to variable rates. The interest rate on the $60 million notional amount is equal to three month LIBOR plus an applicable margin of 1.1575%. The maturity of the swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes. HEP accounts for this swap as an effective fair value hedge, so the swap has only a nominal effect on earnings. The effect of this interest rate swap was recorded in our consolidated financial statements until the deconsolidation of HEP effective July 1, 2005.

At December 31, 2005, 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, 2005. Before July 2004, we invested any available cash only in investment grade, highly liquid investments with maturities of three months or less and hence the interest rate market risk implicit in these cash investments was low. Beginning in July 2004, we are also investing certain available cash 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 also 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.

-53-


	Years Ended December 31,
	2005		2004		2003
Average per produced barrel:

*Consolidated*
Refinery gross margin	$	12.46	$	9.10	$	7.23
Less refinery operating expenses		4.30		3.53		3.58

Net operating margin	$	8.16	$	5.57	$	3.65


(1)		We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only for periods since the purchase date.

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

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


	Years Ended December 31,
	2005			2004			2003
*Navajo Refinery*
Average sales price per produced barrel sold	$	69.11		$	51.42		$	38.95
Times sales of produced refined products sold (BPD)		80,110			78,880			62,570
Times number of days in period		365			366			365

Refined product sales from produced products sold	$	2,020,787		$	1,484,500		$	889,542


*Woods Cross Refinery* ⁽¹⁾
Average sales price per produced barrel sold	$	69.13		$	51.33		$	40.91
Times sales of produced refined products sold (BPD)		26,390			23,520			22,480
Times number of days in period		365			366			214

Refined product sales from produced products sold	$	665,884		$	441,865		$	196,807


*Montana Refinery*
Average sales price per produced barrel sold	$	53.74		$	43.10		$	35.80
Times sales of produced refined products sold (BPD)		8,400			7,970			7,150
Times number of days in period		365			366			365

Refined product sales from produced products sold	$	164,767		$	125,724		$	93,429


Sum of refined product sales from produced products sold from our three refineries ⁽⁴⁾	$	2,851,438		$	2,052,089		$	1,179,778
Add refined product sales from purchased products and rounding ⁽²⁾		278,506			167,422			192,899

Total refined products sales		3,129,944			2,219,511			1,372,677
Add other refining segment revenue ⁽³⁾		64,823			15,186			21,759

Total refining segment revenue		3,194,767			2,234,697			1,394,436
Add HEP sales and other revenue		36,034			28,182			—
Add corporate and other revenues		1,772			1,916			9,258
Subtract consolidations and eliminations		(19,828	)		(18,422	)		(450	)

Sales and other revenues	$	3,212,745		$	2,246,373		$	1,403,244


(1)		We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only for periods since the purchase date.

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

(3)		Other refining segment revenue includes the revenues associated with NK Asphalt Partners subsequent to their consolidation in February 2005 and revenues during 2004 and 2003 from terminal and pipeline assets that are now owned by HEP.

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

-56-


	Years Ended December 31,
	2005		2004		2003
Average sales prices per produced barrel sold	$	67.99	$	50.80	$	38.99
Times sales of produced refined products sold (BPD)		114,900		110,370		82,900
Times number of days in period		365		366		365

Refined product sales from produced products sold	$	2,851,438	$	2,052,089	$	1,179,778

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


	Years Ended December 31,
	2005			2004			2003
*Navajo Refinery*
Average cost of products per produced barrel sold	$	55.50		$	41.26		$	31.52
Times sales of produced refined products sold (BPD)		80,110			78,880			62,570
Times number of days in period		365			366			365

Cost of products for produced products sold	$	1,622,828		$	1,191,180		$	719,855


*Woods Cross Refinery* ⁽¹⁾
Average cost of products per produced barrel sold	$	59.51		$	45.33		$	34.81
Times sales of produced refined products sold (BPD)		26,390			23,520			22,480
Times number of days in period		365			366			214

Cost of products for produced products sold	$	573,221		$	390,215		$	167,461


*Montana Refinery*
Average cost of products per produced barrel sold	$	43.34		$	35.37		$	28.17
Times sales of produced refined products sold (BPD)		8,400			7,970			7,150
Times number of days in period		365			366			365

Cost of products for produced products sold	$	132,880		$	103,175		$	73,517


Sum of cost of products for produced products sold from our three refineries ⁽⁴⁾	$	2,328,929		$	1,684,570		$	960,833
Add refined product costs from purchased products sold, certain hedging gains and rounding ⁽²⁾		279,868			169,849			190,939

Total refined costs of products sold		2,608,797			1,854,419			1,151,772
Add other refining segment costs of products sold ⁽³⁾		47,633			—			—

Total refining segment costs of products sold		2,656,430			1,854,419			1,151,772
Add corporate and other costs of products sold		—			—			4,536
Subtract consolidation and eliminations		(19,828	)		(18,422	)		(450	)

Costs of products sold (exclusive of depreciation, depletion and amortization)	$	2,636,602		$	1,835,997		$	1,155,858


(1)		We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only for periods since the purchase date.

(2)		We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments. Additionally during 2005, we entered into petroleum futures transactions hedging forecasted diesel fuel sales. The positions were fully liquidated during August to November 2005 resulting in gains of $3.2 million for the year ending December 31, 2005, which are recorded as a reduction in costs of products sold.

(3)		Other refining segment costs of products sold include the cost of products for NK Asphalt Partners subsequent to their consolidation in February 2005.

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

-57-


	Years Ended December 31,
	2005		2004		2003
Average cost of products per produced barrel sold	$	55.53	$	41.70	$	31.76
Times sales of produced refined products sold (BPD)		114,900		110,370		82,900
Times number of days in period		365		366		365

Cost of products for produced products sold	$	2,328,929	$	1,684,570	$	960,833

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


	Years Ended December 31,
	2005		2004		2003
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	3.94	$	3.20	$	3.24
Times sales of produced refined products sold (BPD)		80,110		78,880		62,570
Times number of days in period		365		366		365

Refinery operating expenses for produced products sold	$	115,206	$	92,384	$	73,995


*Woods Cross Refinery* ⁽¹⁾
Average refinery operating expenses per produced barrel sold	$	4.61	$	3.92	$	3.92
Times sales of produced refined products sold (BPD)		26,390		23,520		22,480
Times number of days in period		365		366		214

Refinery operating expenses for produced products sold	$	44,405	$	33,745	$	18,858


*Montana Refinery*
Average refinery operating expenses per produced barrel sold	$	6.72	$	5.64	$	5.85
Times sales of produced refined products sold (BPD)		8,400		7,970		7,150
Times number of days in period		365		366		365

Refinery operating expenses for produced products sold	$	20,604	$	16,452	$	15,267


Sum of refinery operating expenses per produced products sold from our three refineries ⁽³⁾	$	180,215	$	142,581	$	108,120
Add other refining segment operating expenses and rounding ⁽²⁾		20,549		19,666		23,120

Total refining segment operating expenses		200,764		162,247		131,240
Add HEP operating expenses		11,836		10,103		—
Add corporate and other costs		59		166		3,023

Operating expenses (exclusive of depreciation, depletion and amortization)	$	212,659	$	172,516	$	134,263


(1)		We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only for periods since the purchase date.

(2)		Other refining segment operating expenses include the marketing costs associated with our refining segment, the operating expenses of NK Asphalt Partners subsequent to their consolidation in February 2005 and the operating expenses during 2004 and 2003 of terminal and pipeline assets now owned by HEP.

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


	Years Ended December 31,
	2005		2004		2003
Average refinery operating expenses per produced barrel sold	$	4.30	$	3.53	$	3.58
Times sales of produced refined products sold (BPD)		114,900		110,370		82,900
Times number of days in period		365		366		365

Refinery operating expenses for produced products sold	$	180,215	$	142,581	$	108,120

-58-

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


	Years Ended December 31,
	2005			2004			2003
*Navajo Refinery*
Net operating margin per barrel	$	9.67		$	6.96		$	4.19
Add average refinery operating expenses per produced barrel		3.94			3.20			3.24

Refinery gross margin per barrel		13.61			10.16			7.43
Add average cost of products per produced barrel sold		55.50			41.26			31.52

Average net sales per produced barrel sold	$	69.11		$	51.42		$	38.95
Times sales of produced refined products sold (BPD)		80,110			78,880			62,570
Times number of days in period		365			366			365

Refined product sales from produced products sold	$	2,020,787		$	1,484,500		$	889,542


*Woods Cross Refinery* ⁽¹⁾
Net operating margin per barrel	$	5.01		$	2.08		$	2.18
Add average refinery operating expenses per produced barrel		4.61			3.92			3.92

Refinery gross margin per barrel		9.62			6.00			6.10
Add average cost of products per produced barrel sold		59.51			45.33			34.81

Average net sales per produced barrel sold	$	69.13		$	51.33		$	40.91
Times sales of produced refined products sold (BPD)		26,390			23,520			22,480
Times number of days in period		365			366			214

Refined product sales from produced products sold	$	665,884		$	441,865		$	196,807


*Montana Refinery*
Net operating margin per barrel	$	3.68		$	2.09		$	1.78
Add average refinery operating expenses per produced barrel		6.72			5.64			5.85

Refinery gross margin per barrel		10.40			7.73			7.63
Add average cost of products per produced barrel sold		43.34			35.37			28.17

Average net sales per produced barrel sold	$	53.74		$	43.10		$	35.80
Times sales of produced refined products sold (BPD)		8,400			7,970			7,150
Times number of days in period		365			366			365

Refined product sales from produced products sold	$	164,767		$	125,724		$	93,429


Sum of refined product sales from produced products sold from our three refineries ⁽⁴⁾	$	2,851,438		$	2,052,089		$	1,179,778
Add refined product sales from purchased products sold and rounding ⁽²⁾		278,506			167,422			192,899

Total refined product sales		3,129,944			2,219,511			1,372,677
Add other refining segment revenue ⁽³⁾		64,823			15,186			21,759

Total refining segment revenue		3,194,767			2,234,697			1,394,436
Add HEP sales and other revenues		36,034			28,182			—
Add corporate and other revenues		1,772			1,916			9,258
Subtract consolidations and eliminations		(19,828	)		(18,422	)		(450	)

Sales and other revenues	$	3,212,745		$	2,246,373		$	1,403,244


(1)		We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only for periods since the purchase date.

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

(3)		Other refining segment revenue includes the revenues associated with NK Asphalt Partners subsequent to their consolidation in February 2005 and revenues during 2004 and 2003 from terminal and pipeline assets that are now owned by HEP.

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

-59-

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited management’s assessment, included in the accompanying “Management’s Report on Its Assessment of the Company’s Internal Control Over Financial Reporting”, that Holly Corporation maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Holly Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that Holly Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the COSO. Also, in our opinion, Holly Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Holly Corporation as of December 31, 2005 and 2004, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2005 of Holly Corporation and our report dated March 6, 2006 expressed an unqualified opinion thereon.


		/s/		ERNST & YOUNG LLP

Dallas, Texas
March 6, 2006

-62-

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2005			2004			2003
	(In thousands)
Cash flows from operating activities:
Net income	$	167,658		$	83,879		$	46,053
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		43,817			40,481			36,275
Deferred income taxes		(5,822	)		(25,384	)		20,297
Minority interest in income of partnerships		6,721			7,575			758
Equity based compensation expense		2,163			3,419			—
Distributions in excess of equity in earnings of Holly Energy Partners and joint ventures		3,050			4,728			3,520
Gain on sale of assets		—			—			(15,814	)
(Increase) decrease in current assets:
Accounts receivable		(128,301	)		(97,397	)		(35,547	)
Inventories		1,797			7,379			(17,453	)
Income taxes receivable		10,735			1,411			(7,165	)
Prepayments and other		795			(3,908	)		995
Increase (decrease) in current liabilities:
Accounts payable		143,289			99,029			64,242
Accrued liabilities		6,155			18,024			2,000
Income taxes payable		1,388			—			—
Turnaround expenditures		(1,077	)		(7,450	)		(25,029	)
Prepaid transportation		—			25,000			—
Other, net		(1,134	)		7,818			2,308

Net cash provided by operating activities		251,234			164,604			75,440

Cash flows from investing activities:
Additions to properties, plants and equipment		(106,262	)		(37,780	)		(74,642	)
Acquisition by Holly Energy Partners of pipeline and terminal assets		(121,853	)		—			—
Decrease in cash due to deconsolidation of Holly Energy Partners		(20,447	)		—			—
Purchase Holly Energy Partners restricted units		—			(223	)		—
Acquisition of Woods Cross refinery and retail stations		—			—			(55,837	)
Investments and advances to joint ventures		—			(3,314	)		(3,328	)
Purchase of additional interests in joint venture, net of cash		(18,360	)		—			(21,369	)
Purchases of marketable securities		(322,046	)		(271,720	)		—
Sales and maturities of marketable securities		268,001			119,034			—
Proceeds from the sale of partial interest in joint venture		832			—			—
Proceeds from sale of pipeline assets		—			—			24,000
Proceeds from sale of retail stations		—			—			8,462

Net cash used for investing activities		(320,135	)		(194,003	)		(122,714	)

Cash flows from financing activities:
Proceeds from issuance of Holly Energy Partners’:
Senior notes, net of underwriter discount		181,955			—			—
Common units, net of offering costs		43,788			141,974			—
Payment of long-term debt		(8,572	)		(8,570	)		(8,572	)
Net increase (decrease) in borrowings under revolving credit agreements		(25,000	)		(25,000	)		50,000
Debt issuance costs		(948	)		(3,603	)		(185	)
Issuance of common stock upon exercise of options		2,782			4,655			369
Purchase of treasury stock		(130,763	)		(15,293	)		(894	)
Sale of treasury stock		1,957			—			—
Cash dividends		(11,243	)		(8,281	)		(5,114	)
Cash distributions to minority interests		(9,486	)		(6,282	)		(1,350	)
Excess tax benefit from equity based compensation		6,035			5,569			234
Other		—			—			210

Net cash provided by financing activities		50,505			85,169			34,698

Cash and cash equivalents:

Increase (decrease) for the period		(18,396	)		55,770			(12,576	)
Beginning of period		67,460			11,690			24,266

End of period	$	49,064		$	67,460		$	11,690

See accompanying notes.

-67-

HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Description of Business: References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In this document, the words “we”, “our”, “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

We are principally an independent petroleum refiner, who produces high value light products such as gasoline, diesel fuel and jet fuel. Navajo Refining Company, L.P., (“Navajo”), one of our wholly-owned subsidiaries, owns a petroleum refinery in Artesia, New Mexico, which Navajo operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery can process sour (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. In June 2003, we completed the acquisition of the Woods Cross refining facility from ConocoPhillips. The Woods Cross refinery (“Woods Cross Refinery”), located just north of Salt Lake City, Utah, is operated by Holly Refining & Marketing Company – Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes regional sweet (lower sulfur) and sour Canadian crude oils. We also own Montana Refining Company (“MRC”), which owns a petroleum refinery in Great Falls, Montana (“Montana Refinery”), which can process primarily sour Canadian crude oils and which primarily serves markets in Montana. As announced on March 2, 2006, we have entered into a definitive agreement with Connacher Oil and Gas Limited (“Connacher”) for the sale of the Montana Refinery (see Note 28). In conjunction with the refining and pipeline operations, we own a system of crude oil gathering pipelines.

In July 2004, we completed an initial public offering of limited partnership interests in Holly Energy Partners, L.P. (“HEP”), a Delaware limited partnership which following its formation was owned 51% by us and 49% by other investors in HEP. On February 28, 2005, HEP closed on the acquisition of assets from Alon USA, Inc. and certain of its affiliates (collectively, “Alon”). This purchase reduced our ownership in HEP to 47.9%. On July 8, 2005, we closed on a transaction for HEP to acquire our two parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities, which reduced our ownership in HEP to 45.0%.

At December 31, 2005, HEP had logistics assets including petroleum product pipelines located in Texas, New Mexico and Oklahoma; eleven refined product terminals; two refinery truck rack facilities, a refined products tank farm facility and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which owns a pipeline that transports liquid petroleum gases, or LPGs, from West Texas to the Texas/Mexico border near El Paso for further transport into Northern Mexico.

In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by a subsidiary of Koch Materials Company (“Koch”) increasing our ownership in NK Asphalt Partners from 49% to 100%. The partnership now does business under the name of “Holly Asphalt Company.” At December 31, 2004, we had a 49% interest in NK Asphalt Partners, which manufactures and markets asphalt and asphalt products in Arizona and New Mexico. See Note 9 for additional information regarding the purchase made in February 2005.

We also conduct a small-scale oil and gas exploration and production program and had a small investment in a joint venture that operates retail gasoline stations and convenience stores in Montana. See Note 9 for information regarding the sale of our 49% interest in MRC Hi-Noon LLC to our joint venture partner on February 28, 2005.

Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures where we have 50% or more ownership. All significant intercompany transactions and balances have been eliminated. The accounts of HEP were consolidated from July 13, 2004 through the deconsolidation effective July 1, 2005.

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

-70-

HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Reclassifications: Certain reclassifications, which we determined to be immaterial, have been made to prior balances to conform to the classifications used for 2005. In addition, the 2004 HEP offering proceeds of $142.0 million, net of formation costs, previously reflected in the 2004 statement of cash flows as part of investing activities were reclassified in the 2004 statement of cash flows as part of financing activities.

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

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

Accounts Receivable: The majority of the accounts receivable are due from companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, is required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal.

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

Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. No impairments of long-lived assets were recorded during the years ended December 31, 2005, 2004 and 2003.

Intangibles and Goodwill: Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. No impairments of intangibles or goodwill were recorded during the years ended December 31, 2005, 2004 and 2003.

Investment in HEP: Through June 30, 2005, our financial statements included the consolidated results of HEP, with the interest we did not own reported as a minority interest in the ownership and earnings. Under the provisions of the Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised) (“FIN 46”), “Consolidation of Variable Interest Entities,” 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 (see Note 2).

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investments in Joint Ventures: We have accounted for investments in and earnings from joint ventures where we have ownership of 50% or less using the equity method.

Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. Pipeline transportation revenues are recognized as products are shipped on our pipelines, including HEP’s pipelines. Additional pipeline transportation revenues result from the lease of an interest in the capacity of an HEP pipeline. All revenues are reported inclusive of shipping and handling costs billed and exclusive of excise taxes. Shipping and handling costs incurred are reported in cost of products sold.

Depreciation: Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 10 to 12 years for refining facilities, 10 to 30 years for pipeline and terminal facilities, 3 to 5 years for transportation vehicles, 10 to 40 years for buildings and improvements and 7 to 30 years for other fixed assets.

Cost Classifications: Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. To provide the desired crude oil to our refineries, we utilize a combination of crude oil purchases from producers and other petroleum companies and enter into crude oil buy/sell exchanges. When crude oil is purchased in excess of the needs of our refineries, we may resell to other purchasers or users of crude oil. The net differential gain/loss on these crude oil transactions is recorded in cost of products sold. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs.

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

Environmental Costs: Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

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

Stock-Based Compensation: In December 2004, the FASB issued SFAS 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide-range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. We elected early adoption of this standard effective July 1, 2005 based on modified retrospective application with early application under SFAS 123 (revised) to prior quarters of 2005. Also as part of this adoption, we recorded a cumulative effect of a change in accounting principle relating to our performance units due to the initial effect of measuring these awards at fair value where they were previously measured at intrinsic value. See Note 4 for additional information regarding our adoption of SFAS No. 123 (revised).

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

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in the balance sheet and measured at their fair value. Changes in the derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. See Note 18 for additional information on derivative instruments and hedging activities.

New Accounting Pronouncements:

In December 2004, the FASB issued SFAS No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4.” This amendment requires abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) to be recognized as current-period charges. This standard also requires that the allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. This standard is effective for fiscal years beginning after June 15, 2005. We will adopt the standard effective for our 2006 year. We do not anticipate the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principle and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement becomes effective for fiscal years beginning after December 15, 2005. The impact of this standard will be determined upon the issuance of new standards or our voluntary change in an accounting principle.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under SFAS No. 143. FIN 47 is effective for fiscal years ending after December 15, 2005. We adopted the standard effective as of December 31, 2005. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

The Emerging Issues Task Force reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it in September 2005. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The consensus in this Issue is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. We have certain crude oil transactions that are accounted for on a net cost basis. We do not believe that our revenues or cost of sales will be materially impacted by applying the Issue’s consensus.

NOTE 2: Investment in Holly Energy Partners

On July 13, 2004, HEP closed its initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 share over-allotment option that was exercised by the underwriters. HEP’s common units trade on the New York Stock Exchange under the symbol “HEP”. Proceeds to HEP from the sale of the units were $145.5 million, net of underwriting commissions. After the offering, we owned a 51% interest in HEP, consisting of a 2% general partner interest and a 49% subordinated limited partner interest. The initial public offering represented

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the sale by us of a 49% interest in HEP. Following HEP’s acquisition of our intermediate feedstock pipelines, as discussed below, our current ownership interest in HEP is 45.0%, including the 2% general partner interest. HEP was formed to acquire, own and operate substantially all of our refined product pipeline and terminalling assets that support our refining and marketing operations in West Texas, New Mexico, Utah and Arizona and to own our 70% interest in Rio Grande, all of which were contributed to HEP upon the closing of its initial public offering. In July 2004, HEP repaid us for $30.1 million of debt and made a distribution to us of $125.6 million. Beginning with the third quarter of 2004, we consolidated the results of HEP with minority interest treatment for the common units. In connection with the initial public offering, we entered into a 15-year pipelines and terminals agreement with HEP expiring in 2019 (“HEP PTA”), under which we agreed generally to transport or terminal volumes on certain of HEP’s initial facilities that result in revenues that equal or exceed a specified minimum revenue amount annually (which currently is at $36.7 million per year and will adjust upward based on the increase in the producer price index) over the term of the agreement. Additionally, we agreed to indemnify HEP up to an aggregate amount of $15 million for ten years for any environmental noncompliance and remediation liabilities associated with the initial assets transferred to HEP and occurring or existing prior to the date of the initial public offering.

On February 28, 2005, HEP closed its acquisition from Alon of four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s refinery in Big Spring, Texas. The total consideration paid by HEP for these pipeline and terminal assets was $120 million in cash and 937,500 Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units in five years following the acquisition date. Following the closing of this transaction, we owned 47.9% of HEP including the 2% general partner interest. HEP financed the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015 (“HEP Senior Notes”). HEP used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under HEP’s credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. The consideration paid for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The aggregate consideration amounted to $146.6 million, which consisted of $24.7 million fair value of HEP’s Class B subordinated units, $120 million in cash and $1.9 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.9 million and an intangible asset of $59.7 million, representing the value of the 15-year pipelines and terminals agreement.

On July 8, 2005, we closed on a transaction in which HEP acquired our two parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. The total consideration was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. HEP financed the approximately $77.7 million cash portion of the consideration for the intermediate pipelines with the proceeds raised from the private sale, which closed simultaneously with the acquisition, of 1.1 million of its common units for $45.1 million to a limited number of institutional investors and the offering, completed in June 2005, of an additional $35.0 million in principal amount of HEP Senior Notes. This acquisition was made pursuant to an option to purchase these pipelines which we granted to HEP at the time of the initial public offering in July 2004. We have agreed to a 15-year pipelines agreement expiring in 2020 (“HEP IPA”) with a minimum annual volume commitment of 72,000 BPD on the pipelines, which will result in minimum annual revenues to HEP of $11.8 million per year (subject to upward adjustment for future periods based on the producer price index) over the life of the agreement. In addition, we have agreed to indemnify HEP for an additional $2.5 million (bringing the total indemnification for environmental matters provided by us to HEP to $17.5 million), for any environmental noncompliance and remediation liabilities occurring or existing prior to the closing date. As a result of this transaction, our ownership interest in HEP has been reduced to 45.0%, including the 2% general partner interest.

We hold 7,000,000 subordinated units of HEP at December 31, 2005. Our rights as holder of subordinated units to receive distributions of cash from HEP are subordinated to the rights of the common unitholders to receive such distributions.

In January 2003 (revised December 2003), the FASB issued FIN 46, which we adopted on December 31, 2003. This interpretation defined 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

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

allocated a majority of the entity’s expected losses or expected residual returns. Through June 30, 2005, our financial statements included the consolidated results of HEP, with the interest we did not own treated as a minority interest in the ownership and earnings. HEP is a VIE as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines, we have determined that our beneficial variable interest in HEP was less than 50%; and therefore as required by FIN 46, we deconsolidated HEP effective as of July 1, 2005. The deconsolidation has been 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 does have 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.

As of July 1, 2005, the impact of deconsolidation of HEP was an increase in the liability account of investments in HEP of $83.8 million, a decrease in property, plant and equipment of $157.8 million, a decrease in cash of $20.4 million, a decrease in other current assets of $3.6 million, a decrease in transportation agreements of $62.7 million, a decrease in other assets of $4.5 million, a decrease in minority interest of $179.5 million, a decrease in current liabilities of $3.9 million and a decrease in other long-term liabilities of $149.4 million.

In addition to the intermediate feedstock pipelines acquired by HEP in July 2005, we contributed all of the initial assets of HEP. As these transactions were among entities under common control, the assets were recorded at historical cost by HEP and we did not recognize a gain on the initial contribution or the intermediate pipelines acquisition. The intermediate pipelines transaction resulted in a payment to us from HEP of $71.9 million in excess of our historical basis. Since the historical basis was less than the cash received on the transactions, our investment in HEP is a negative investment. The investment balance was eliminated in consolidation until the deconsolidation of HEP on July 1, 2005. The following table sets forth the changes in our investment account balance with HEP subsequent to its initial public offering in July 2004.


Our historic basis in the net assets contributed to or acquired by HEP	$	45,982
Distributions received for the net assets contributed to or acquired by HEP		(203,263	)
General partner capital contributions subsequent to HEP’s formation		1,591
Equity in the earnings of HEP subsequent to its formation		18,458
Regular quarterly distributions from HEP		(19,794	)

Investment in HEP balance at December 31, 2005	$	(157,026	)

The following tables provide summary financial results for HEP subsequent to its formation on July 13, 2004.


	December 31,		December 31,
	2005		2004
	(In thousands)
Current assets	$	28,705	$	22,533
Properties and equipment, net		162,298		74,626
Transportation agreements and other		63,772		6,599

Total assets	$	254,775	$	103,758


Current liabilities	$	9,251	$	3,413
Long-term liabilities		181,711		25,585
Minority interest		11,753		13,232
Partners’ equity		52,060		61,528

Total liabilities and partners’ equity	$	254,775	$	103,758

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Years Ended December 31,
	2005			2004
	(In thousands)
Revenues	$	80,120		$	28,182
Operating costs and expenses		43,580			15,204

Operating income		36,540			12,978
Other expenses, net		(9,724	)		(1,588	)

Net income	$	26,816		$	11,390

We have related party transactions with HEP for pipeline and terminal services, certain employee costs, insurance costs, and administrative costs under the HEP PTA, HEP IPA and Omnibus Agreement. The related party amounts reported below include all activity with HEP during the periods reported, including transactions both before and after the deconsolidation of HEP effective July 1, 2005. Pipeline and terminal expenses paid to HEP were $44.2 million and $17.9 million for the years ended December 31, 2005 and 2004, respectively. Under the Omnibus Agreement, we charged HEP $2.0 million and $0.9 million for general and administrative services and $6.5 million and $2.2 million for reimbursement of employee costs incurred by us supporting HEP’s operations, which we recorded as a reduction in expenses, for 2005 and 2004, respectively. During 2004, HEP reimbursed Holly $3.9 million for certain formation, debt issuance and other costs paid on HEP’s behalf. In 2005, we reimbursed HEP $0.2 million for costs paid on our behalf. In 2005 and 2004, we received $16.5 million and $3.2 million, respectively, in distributions from HEP as regular distributions on our subordinated and common units and general partner interest. In July 2005, HEP acquired our intermediate pipelines, which included a payment to us from HEP of $71.9 million in excess of the historical basis of the assets. In the year ended December 31, 2004, HEP distributed $125.6 million to us concurrent with HEP’s public offering and repaid us $30.1 million for short-term borrowings. We also had a net payable to HEP of $3.6 million and $2.1 million at December 31, 2005 and 2004, respectively.

NOTE 3: Earnings Per Share

Basic income per share is calculated as net income divided by the average number of shares of common stock outstanding. Diluted income per share assumes, when dilutive, issuance of the net incremental shares from stock options and variable performance shares. Income per share amounts reflect the two-for-one stock split in August 2004. The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations for income:


	Years Ended December 31,
	2005		2004		2003
	(In thousands, except per share data)
Net income	$	167,658	$	83,879	$	46,053

Average number of shares of common stock outstanding		30,864		31,390		31,010
Effect of dilutive stock options and variable restricted shares		758		780		1,022

Average number of shares of common stock outstanding assuming dilution		31,622		32,170		32,032


Income per share – basic	$	5.43	$	2.67	$	1.49


Income per share – diluted	$	5.30	$	2.61	$	1.44

NOTE 4: Stock-Based Compensation

We elected early adoption of SFAS 123 (revised) on July 1, 2005 based on modified retrospective application with early application under SFAS 123 (revised) to prior quarters in 2005. Also as part of this adoption, we recorded a cumulative effect of a change in accounting principle relating to our performance units, as discussed below.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 31, 2005, we had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for these plans was $7.6 million, $11.8 million and zero for the years ended December 31, 2005, 2004 and 2003 respectively. No compensation cost was recorded during 2004 or 2003 related to the stock options as the stock options were being measured in accordance with the provisions of APB Opinion No. 25 and related interpretations. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $3.0 million, $4.6 million and zero for the years ended December 31, 2005, 2004 and 2003, respectively. It is currently our practice to issue new shares for settlement of option exercises or restricted stock grants. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs over the pro-rata periods, which results in a higher expense in the earlier periods of the grants. At December 31, 2005, 1,572,646 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which reservation allows for awards of options, restricted stock, or other performance awards.

Previously awarded stock options and all other compensation arrangements based on the market value of our common stock have been adjusted to reflect the two-for-one stock split in August 2004.

Stock Options

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

A summary of option activity as of December 31, 2005, and changes during the year ended December 31, 2005 is presented below:


						Weighted-
				Weighted–		Average		Aggregate
				Average		Remaining		Intrinsic
				Exercise		Contractual		Value
Options	Shares			Price		Term		($000)
Outstanding at January 1, 2005		1,734,400		$	5.19
Exercised		(490,650	)		5.67
Forfeited or expired		(4,000	)		5.95

Outstanding at December 31, 2005		1,239,750		$	4.99		4.5	$	66,792

Exercisable at December 31, 2005		1,035,350		$	4.73		4.3	$	56,054

The total intrinsic value of options exercised during the years ended December 31, 2005, 2004 and 2003, was $14.9 million, $14.3 million and $0.8 million, respectively.

A summary of the status of our nonvested options as of December 31, 2005 and changes during the year ended December 31, 2005, is presented below:


				Weighted-
				Average
				Grant-Date
Nonvested Options	Options			Fair Value
Nonvested at January 1, 2005		508,000		$	1.85
Vested		(299,600	)		1.72
Forfeited		(4,000	)		1.82

Nonvested at December 31, 2005		204,400		$	2.03

As of December 31, 2005, there was approximately $140,000 of total unrecognized compensation cost related to the stock options granted. That cost is expected to be recognized over a weighted-average period of four months. The

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

total fair value of options vested during the years ended December 31, 2005, 2004 and 2003, was $0.5 million, $0.8 million and $0.8 million, respectively.

Cash received from option exercises under the stock option plans for the years ended December 31, 2005, 2004 and 2003, was $2.8 million, $4.7 million and $0.4 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $5.8 million, $5.6 million and $0.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Restricted Stock

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

A summary of restricted stock activity as of December 31, 2005, and changes during the year ended December 31, 2005 is presented below:


				Weighted–
				Average
				Grant-Date		Aggregate Intrinsic
Restricted Stock	Grants			Fair Value		Value ($000)
Outstanding at January 1, 2005 (not vested)		288,104		$	15.00
Vesting and transfer of ownership to recipients		(74,450	)		13.63
Granted		64,600			34.06
Forfeited		(5,350	)		25.14

Outstanding at December 31, 2005 (not vested)		272,904		$	19.69	$	16,066

The weighted-average grant-date fair value of restricted stock granted during 2004 was $15.00. No shares of restricted stock were granted in 2003. The total intrinsic value of restricted stock vested and transferred to recipients during the year ended December 31, 2005 was $2.5 million. No shares of restricted stock were vested and transferred to recipients during 2004 or 2003. As of December 31, 2005, there was $2.8 million of total unrecognized compensation cost related to nonvested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 2.4 years. The total fair value of shares vested during the year ended December 31, 2005 was $1.0 million.

Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units which are payable in cash upon meeting performance criteria over the service period, and generally vest over a period of one to three years. The cash benefit payable under these grants is based upon our share price and upon our total shareholder return during the requisite period as compared to the total shareholder return of our peer group of refining companies. The fair value of each performance share unit award is being revalued quarterly based on our valuation model and the corresponding expense is being amortized over the vesting periods.

Subsequent to December 31, 2005, we initiated a plan to amend by agreement performance share unit agreements between us and certain grantees to provide that the payment of awards under the agreements as amended will be made in the form of our common stock rather than in cash.

The fair value of the performance share units, payable in cash, is based on an expected-cash-flow approach applied at the grant date and at the end of each subsequent quarter. The analysis utilizes the current stock price, dividend yield, historical total returns as of the measurement date, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns and comparison of expected total returns with the peer

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

group. The expected total return and historical standard deviation are applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns. For our performance share units, the price of the stock at December 31, 2005 was $58.87, the latest quarterly dividend was $0.10, and the risk-free rates range from 4.38% to 4.41%, depending on the remaining performance period. The inputs affecting the range of expected total returns for us and the peer group are based on a capital asset pricing model utilizing information available at each measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:


			Standard
Company	Expected Return on Equity		Deviation (Monthly)
Holly	11.75	%	9.7% to 11.7%
Peer group	9.75% to 13.5%		6.4% to 15.4%

A summary of performance share units activity as of December 31, 2005, and changes during the year ended December 31, 2005 is presented below:


Performance Share Units	Grants
Outstanding at January 1, 2005 (not vested)		277,350
Vesting and payment of cash benefit to recipients		(162,900	)
Granted		69,162
Forfeited		(5,350	)

Outstanding at December 31, 2005 (not vested)		178,262

The total amount of cash paid related to vested performance share units during the year ended December 31, 2005 was $6.3 million. There was no cash paid related to the units during 2004 or 2003. As of December 31, 2005, the liability associated with these awards was $7.0 million and is recorded in accrued liabilities on our consolidated balance sheet. Based on the weighted average fair value at December 31, 2005 of $73.90, there was $6.2 million of total unrecognized compensation cost related to nonvested performance share units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

With the adoption of SFAS 123 (revised), we recorded a cumulative effect of a change in accounting principle relating to our performance units, due to the initial effect of measuring these awards at fair value, where previously they were measured at intrinsic value. The total cumulative effect of the change in accounting principle recorded upon adoption was a gain of approximately $669,000, net of deferred tax expense of approximately $426,000.

The following table represents the effect on net income and earnings per share as if we had applied the fair value based method and recognition provisions of SFAS 123 to stock based employee compensation in the years ended December 31, 2004 and 2003.


	Years Ended December 31,
	2004		2003
	(In thousands, except per share data)
Net income, as reported	$	83,879	$	46,053
Deduct: Total stock-based employee compensation expense determined under the fair value method for stock option awards, net of related tax effects		371		453

Pro-forma net income	$	83,508	$	45,600


Net income per share – basic
As reported	$	2.67	$	1.49
Pro-forma	$	2.66	$	1.47

Net income per share – diluted
As reported	$	2.61	$	1.44
Pro-forma	$	2.60	$	1.42

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5: Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities.

Starting in the third quarter of 2004, we began investing in highly-rated marketable debt securities primarily issued by government entities that have maturities at the date of purchase of greater than three months. These securities include investments in variable rate demand notes (“VRDN”) and auction rate securities (“ARS”). Although VRDN and ARS 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. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are temporary and reported as a component of accumulated other comprehensive income.

The following is a summary of our available-for-sale securities at December 31, 2005:


	Available-for-Sale Securities
						Estimated
			Gross			Fair Value
			Unrealized			(Net Carrying
	Amortized Cost		Losses			Amount)
	(In thousands)
States and political subdivisions	$	205,514	$	(491	)	$	205,023
Corporate debt securities		755		—			755

Total debt securities	$	206,269	$	(491	)	$	205,778

Interest income for the year ended December 31, 2005 included $5.9 million of interest earned, $0.3 million in realized losses and amortization of $1.4 million in net premiums paid related to our marketable debt securities. We had 220 sales and maturities during 2005 in which we received a total of $268.0 million. The realized losses represent the difference between the purchase price, as amortized, and market value on the maturity date or sales date.

The following is a summary of our available-for-sale securities at December 31, 2004:


	Available-for-Sale Securities
					Estimated
			Gross		Fair Value
			Unrealized		(Net Carrying
	Amortized Cost		Losses		Amount)
	(In thousands)
U.S. Treasury	$	18,087	$	144	$	17,943
U.S. government agency		2,484		—		2,484
Asset backed government and corporate securities		2,301		—		2,301
States and political subdivisions		118,341		274		118,067
Corporate debt securities		11,011		1		11,010

Total debt securities	$	152,224	$	419	$	151,805

Interest income for the year ended December 31, 2004 included $1.7 million of interest earned, less than $0.1 million in realized losses and amortization of $0.2 million in net premiums paid related to our marketable debt securities. We had 61 sales and maturities during 2004 in which we received a total of $119.0 million. The realized losses represent the difference between the purchase price and market value on the maturity date or sales date.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6: Accounts Receivable


	December 31,
	2005		2004
	(In thousands)
Product and transportation	$	154,365	$	105,998
Crude oil resales		254,734		175,732
Related party receivable		1,434		—

	$	410,533	$	281,730

Crude oil resales generally represent the sell side of reciprocal crude oil buy/sell exchange arrangements, with an approximate like amount reflected in accounts payable. The net differential of these crude oil buy/sell exchanges involved in supplying crude oil to the refineries is reflected in cost of sales and results principally from crude oil type and location differences. The net differential of crude oil buy/sell exchanges involved in pipeline transportation is reflected in revenue since the exchanges were entered into as a means of compensation for pipeline services. In many cases, we enter into net settlement agreements relating to the buy/sell arrangements, which may mitigate credit risk.

NOTE 7: Inventories


	December 31,
	2005		2004
	(In thousands)
Crude oil	$	25,996	$	20,213
Other raw materials and unfinished products ⁽¹⁾		8,937		13,718
Finished products ⁽²⁾		60,923		58,613
Process chemicals ⁽³⁾		6,739		4,206
Repairs and maintenance supplies and other		8,681		8,218

	$	111,276	$	104,968


(1)		Other raw materials and unfinished products include feedstocks and blendstocks, other than crude. The inventory carrying value includes the cost of the raw materials and transportation.

(2)		Finished products include gasolines, jet fuels, diesels, asphalts, LPG’s and residual fuels. The inventory carrying value includes the cost of raw materials including transportation and direct production costs.

(3)		Process chemicals include catalysts, additives and other chemicals. The inventory carrying value includes the cost of the purchased chemicals and related freight.

The excess of current cost over the LIFO value of inventory was $146.2 million and $78.7 million at December 31, 2005 and 2004, respectively. We recognized $4.1 million and $4.9 million in income in the years ended December 31, 2005 and 2004, respectively, resulting from liquidations of certain LIFO inventory quantities that were carried at lower costs as compared to current costs.

Inventories are stated at the lower of cost, using the LIFO method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8: Properties, Plants and Equipment


	December 31,
	2005			2004
	(In thousands)
Land, buildings and improvements	$	16,630		$	20,656
Refining facilities		360,667			348,817
Pipelines and terminals		52,160			142,450
Transportation vehicles		18,538			22,203
Oil and gas exploration and development		3,638			3,635
Other fixed assets		16,375			16,675
Construction in progress		105,874			17,711

		573,882			572,147
Accumulated depreciation, depletion and amortization		(244,307	)		(259,874	)

	$	329,575		$	312,273

We did not capitalize any interest for the years ended December 31, 2005 and 2004.

NOTE 9: Investments in Joint Ventures

Rio Grande is 70% owned by HEP and 30% owned by BP p.l.c., and serves northern Mexico by transporting LPGs from a point near Odessa, Texas to a subsidiary of Petr\leos Mexicanos (“PEMEX”) at a point near El Paso, Texas. The PEMEX subsidiary then transports the LPG’s to its Mendez terminal near Juarez, Mexico. Deliveries by the joint venture began in April 1997. Prior to the initial public offering of HEP on July 13, 2004, Rio Grande was owned 70% by us and 30% by BP p.l.c. Prior to June 30, 2003, Rio Grande was owed 25% by us and 75% collectively by two parties unaffiliated with us. On June 30, 2003, we purchased an additional 45% interest in Rio Grande, through a wholly-owned indirect subsidiary, adding to the 25% interest that our subsidiary already owned. Prior to the 45% acquisition, we accounted for the earnings of the joint venture using the equity method. Effective with the purchase, we consolidate the results of Rio Grande and reflect a minority interest in ownership and earnings. The purchase price for the additional 45% interest was $28.7 million, less cash of $7.3 million that we recorded due to the consolidation of Rio Grande at the time of the additional 45% acquisition. In addition to cash, at the date of the acquisition, Rio Grande owned current assets of $0.6 million, net property, plant and equipment of $34.9 million, other net assets of $7.8 million and current liabilities of $0.4 million. The 70% interest in Rio Grande was one of the assets contributed to HEP upon the closing of its initial public offering.

Prior to February 2005, NK Asphalt Partners was owned 49% by us and 51% by Koch, and did business under the name “Koch Asphalt Solutions – Southwest.” We accounted for this investment using the equity method. In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by Koch for $16.9 million plus working capital. This purchase increased our ownership in NK Asphalt Partners from 49% to 100% and eliminated any further obligations we had with respect to additional contributions under the joint venture agreement. The partnership manufactures and markets asphalt and asphalt products from various terminals in Arizona and New Mexico and now does business under the name “Holly Asphalt Company.” From the date of acquisition of the additional 51%, we have consolidated the results of NK Asphalt Partners in our consolidated financial statements. All intercompany transactions have been eliminated in consolidation. The purchase price was allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. 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 the 51% acquisition. In addition to the cash, at the date of the acquisition, we recorded current assets of $11.7 million, net property, plant and equipment of $20.4 million, intangible assets of $5.2 million, goodwill of $1.0 million, and current liabilities of $8.5 million and eliminated our equity investment. Sales to the joint venture during 2005, prior to the acquisition, were $3.9 million, and during the years ended December 31, 2004 and 2003 were $32.2 million and $31.0 million, respectively.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

collectability of advances to the joint venture and related accrued interest. On February 28, 2005, we sold our 49% interest to our joint venture partner and agreed to accept partial payment on the advances we previously made to the joint venture. In connection with this transaction, we received $0.8 million, which resulted in a book gain to us of $0.5 million.

NOTE 10: Other Assets


	December 31,
	2005		2004
	(In thousands)
Turnaround costs (long-term portion)	$	7,480	$	13,535
Intangibles and other		14,116		15,986

	$	21,596	$	29,521

NOTE 11: Environmental Costs

Consistent with our accounting policy for environmental remediation costs, we expensed $0.5 million, $0.8 million and $3.9 million for the years ended December 31, 2005, 2004 and 2003, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheet was $3.1 million and $3.6 million at December 31, 2005 and 2004, respectively, of which $2.0 million and $2.4 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 12: Debt


	December 31,
	2005		2004
	(In thousands)
Senior Notes
Series C	$	—	$	5,572
Series D		—		3,000

		—		8,572

HEP credit agreement facility		—		25,000


Total debt		—		33,572

Current maturities of long-term debt		—		(8,572	)

Total debt classified as long-term	$	—	$	25,000

Senior Notes: In November 1995, we completed the funding from a group of insurance companies of a new private placement of Senior Notes (“HOC Senior Notes”) in the amount of $39.0 million and the extension of $21.0 million of previously outstanding HOC Senior Notes. The $39.0 million Series C Notes had a 10-year life, required equal annual principal payments beginning December 15, 1999, and bore interest at 7.62%. The $21.0 million Series D Notes, had a 10-year life, required equal annual principal payments beginning December 15, 1999, and bore interest at an initial rate of 10.16%, with reductions to 7.82% for the periods subsequent to June 15, 2001. The $8.6 million remaining balance at December 31, 2004 of these notes was paid in full in December 2005.

Credit Facility: On July 1, 2004, we entered into a new $175 million secured revolving credit facility with Bank of America as administrative agent and lender, with a term of four years and an option to increase the facility to $225 million subject to certain conditions. The new credit facility replaces our prior revolving credit facility with the Canadian Imperial Bank of Commerce and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. Interest on the borrowings is based upon, at our option, (i) the Eurodollar rate plus an applicable rate ranging from 1.25% to 2.50% per annum for each Eurodollar loan and (ii) the

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

base rate plus an applicable rate ranging from 0.00% to 1.25% per annum for each base rate loan. A fee ranging from 1.25% to 2.50% per annum is payable on the outstanding balance of all letters of credit and a commitment fee ranging from 0.30% to 0.50% per annum is payable on the unused portion of the facility. Such interest rate margins and fees are determined based on a quarterly calculation of the ratio of our debt to EBITDA. The borrowing base, which secures the facility, consists of accounts receivable and inventory, and at our option, pledged cash and cash equivalents. The credit facility imposes usual and customary requirements for this type of credit facility, including: (i) maintenance of certain levels of consolidated tangible net worth, interest coverage and leverage ratios; (ii) limitations on liens, investments, indebtedness and dividends; and (iii) a prohibition on changes in control. We were in compliance with all covenants at December 31, 2005. At December 31, 2005, we had outstanding letters of credit totaling $2.3 million, and no outstanding borrowings under our credit facility. The unused commitment under our current credit facility was $172.7 million at December 31, 2005.

The average and maximum amounts outstanding and the effective average interest rate for borrowings under our credit facilities, exclusive of HEP borrowings, during the years ended December 31, 2005 and 2004, were as follows:


	December 31,
	2005		2004
	(Dollars in thousands)
Average amount outstanding	$	—	$	15,888
Maximum balance	$	—	$	80,000
Effective average interest rate		—		2.9	%

We made cash interest payments of $2.0 million and $2.7 million for the years ended December 31, 2005 and 2004, respectively.

HEP Debt Information

As HEP is no longer consolidated in our financial statements effective July 1, 2005 (see Note 2), we no longer include the debt of HEP in our consolidated financial statements. As we reported HEP as a consolidated subsidiary during the six months ended June 30, 2005, the following summarizes HEP’s debt activity during the year.

HEP’s Credit Facility

One of our affiliates, Holly Energy Partners — Operating, L.P., a wholly-owned subsidiary of HEP, entered into a four-year $100 million credit facility with Union Bank of California, as administrative agent and lender, in conjunction with the initial public offering of HEP, with an option to increase the amount to $175 million under certain conditions. The credit facility is available to fund capital expenditures, acquisitions, working capital and for general partnership purposes. The credit facility matures in July 2008. The credit facility was amended effective February 28, 2005 to allow for the closing of the Alon transaction and the related HEP Senior Notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from its senior note offering, HEP repaid $30 million of outstanding indebtedness under the credit facility, including $5 million drawn shortly before the closing of the Alon transaction. The credit facility was amended effective July 8, 2005 to allow for the closing of our intermediate pipelines transaction as well as to amend certain of the restrictive covenants. As of December 31, 2005, HEP did not have any borrowings outstanding under the facility.

HEP’s Senior Notes Due 2015

HEP financed the $120 million cash portion of the Alon transaction through its private offering on February 28, 2005 of $150 million principal amount of HEP Senior Notes. HEP used the balance to repay $30 million of outstanding indebtedness under its credit facility, including $5 million drawn shortly before the closing of the Alon transaction.

HEP financed a portion of the cash piece of the consideration for the intermediate pipelines with the private offering in June 2005 of an additional $35.0 million in principal amount of the HEP Senior Notes.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Risk Management

HEP has entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of its HEP Senior Notes from a fixed rate to variable rates. The interest rate on the $60 million notional amount will be equal to the three month LIBOR rate plus an applicable margin of 1.1575%, which equaled an effective interest rate of 4.5% on $60 million of the debt during the six months ended June 30, 2005, which represents the portion of 2005 during which HEP was a consolidated subsidiary. The maturity of the swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes. HEP accounts for this swap as an effective fair value hedge, so the swap has only a nominal effect on earnings.

NOTE 13: Minority Interests

Since HEP is no longer consolidated in our financial statements effective July 1, 2005 (see Note 2), we no longer have minority interest reported on our consolidated balance sheet.

The following table sets forth the changes in the minority interest balance attributable to third party investors’ interests in HEP. The opening balance represents our minority interest in Rio Grande (see Note 9) as of the date of the initial public offering of HEP, as our interest in Rio Grande was contributed to HEP.


Minority interest prior to initial public offering of HEP	$	13,263
Net proceeds from initial public offering on July 13, 2004		145,460
HEP’s formation costs relating to initial public offering		(3,486	)
Minority interest share of HEP earnings from July 13, 2004 to December 31, 2004		6,538
Cash distribution to minority interests		(4,032	)
Purchase HEP restricted units		(223	)
Other		30


Minority interest at December 31, 2004	$	157,550
Minority interests’ share of HEP earnings from January 1, 2005 to June 30, 2005		6,721
Cash distribution to minority interests		(9,486	)
Issuance by HEP of Class B subordinated units in conjunction with Alon asset acquisition		24,674
Amortization of HEP restricted units		25
Deconsolidation of HEP		(179,484	)


Minority interest at December 31, 2005	$	—

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net periodic pension expense consisted of the following components:


	Year Ended December 31
	2005			2004			2003
				(In thousands)
Service cost – benefit earned during the year	$	3,630		$	3,042		$	2,281
Interest cost on projected benefit obligations		3,790			3,520			3,239
Expected return on plan assets		(3,163	)		(2,882	)		(2,115	)
Amortization of prior service cost		279			261			261
Amortization of net loss		956			685			600

Net periodic pension expense	$	5,492		$	4,626		$	4,266

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


	Year Ended December 31,
	2005			2004			2003
				(In thousands)
Discount rate		6.00	%		6.25	%		7.04	%
Rate of future compensation increases		4.00	%		4.25	%		4.69	%
Expected long-term rate of return on assets		8.50	%		8.50	%		8.50	%

The asset allocation for our retirement plan at year end, by asset category, follows:


				Percentage of Plan Assets at
				Year End
	Target
	Allocation			December 31,			December 31,
Asset Category	2006			2005			2004
Equity securities		70	%		71	%		72	%
Debt Securities		30	%		29	%		28	%

Total		100	%		100	%		100	%

The investment policy developed for the Holly Corporation Pension Plan (the “Plan”) has been designed exclusively for the purpose of providing the highest probabilities of delivering benefits to Plan members and beneficiaries. Among the factors considered in developing the investment policy are: the Plans’ primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation.

The most important component of the investment strategy is the asset allocation between the various classes of securities available to the Plan for investment purposes. The current target asset allocation is 70% equity investments and 30% fixed income investments. The equity allocation is well diversified among the investment styles of large capitalization growth, large capitalization value, small capitalization and international. Equity and fixed income fund managers have been selected based on return/risk track records over time.

The expected long-term rate of returns on Plan assets is 8.5% and is based on historical investment returns. The assumed long-term rate of return on equity and fixed income investments is 10% and 5%, respectively, and using the Plan’s asset allocation target of 70% equities and 30% fixed income, the overall assumed rate of return on the Plan is 8.5%.

We expect to contribute between zero to $6.0 million to the retirement plan in 2006. Benefit payments, which reflect expected future service, are expected to be paid as follows: $3.8 million in 2006; $4.7 million in 2007; $5.3 million in 2008; $5.6 million in 2009; $6.2 million in 2010 and $42.7 million in 2011-2015.

Retirement Restoration Plan: We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. We expensed $0.9 million, $0.6 million and $0.4 million for the years ended December 31, 2005, 2004 and 2003, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheet was $4.9 million and $4.2 million at December 31, 2005 and 2004, respectively. As of December 31, 2005, the projected benefit

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

obligation under this plan was $5.7 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.3 million in 2006; $0.4 million in 2007; $0.4 million in 2008; $0.4 million in 2009; $0.4 million in 2010 and $2.2 million in 2011-2014.

Defined Contribution Plans: We have defined contribution (“401(k)”) plans that cover substantially all employees. Our contributions are based on employee’s compensation and partially match employee contributions. We expensed $1.4 million, $1.3 million and $1.4 million for the years ended December 31, 2005, 2004 and 2003 in connection with these plans.

Postretirement Medical Plans: We adopted an unfunded postretirement medical plan as part of the voluntary early retirement program offered to eligible employees in fiscal 2000. As part of the early retirement program, we agreed to allow retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. The accrued liability reflected in the consolidated balance sheet was $2.4 million and $2.5 million at December 31, 2005 and 2004, respectively, related to this plan.

Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. Periodic costs under this plan have historically been insignificant.

As of December 31, 2005, the total accumulated postretirement benefit obligation under our postretirement medical plans was $5.0 million.

NOTE 18: Derivative Instruments and Hedging Activities

We periodically utilize petroleum commodity futures contracts to reduce our exposure to the 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, as amended. We believe these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, as amended, 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, as amended.

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 $535,000 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 beginning in July 2005 relates to forecasted sales of diesel fuel from our refineries, where our principal objective is to take advantage of the recent high 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

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

In December 2002, we entered into cash flow hedges relating to certain forecasted transactions to buy crude oil and sell gasoline in March 2003. The purpose of the hedges was to help protect us from the risk that the refinery margin would decline with respect to the hedged crude oil and refined products. To affect the hedges, we entered into gasoline and crude oil futures transactions. Gains and losses reported in accumulated other comprehensive income were reclassified into income when the forecasted transactions occurred. During 2002, we marked the value of the outstanding hedges to fair value in accordance with SFAS 133 and included $0.1 million in comprehensive income. In March 2003, as the forecasted transactions occurred, we reclassified $0.1 million of actual losses from comprehensive income to cost of sales. The ineffective portion of the hedges resulted in a less than $0.1 million gain that was also included in cost of sales.

In October 2003, we entered into price swaps to help manage the exposure to price volatility relating to forecasted purchases of natural gas from December 2003 to March 2004. These transactions were designated as cash flow hedges of forecasted purchases. The contracts to hedge natural gas costs were for 6,000, 500, and 2,000 MMBtu per day for the Navajo Refinery, Montana Refinery, and the Woods Cross Refinery, respectively. The December 2003 contracts resulted in net realized losses of $0.1 million and were recorded into refining operating costs. At December 31, 2003, included in comprehensive income was a gain of $0.6 million, as the values of the outstanding hedges were marked to the current fair value, in accordance with SFAS No. 133. The January to March 2004 contracts resulted in net realized gains of $0.3 million and were recorded as a reduction to refinery operating expenses. There was no ineffective portion of these hedges, and since March 31, 2004, no price swaps have been outstanding.

NOTE 19: Lease Commitments

We lease certain facilities, pipelines and equipment under operating leases, most of which contain renewal options. At December 31, 2005, the minimum future rental commitments under operating leases having noncancellable lease terms in excess of one year are as follows (in thousands):


2006	$	2,510
2007		2,371
2008		1,789
2009		1,569
2010		1,257
Thereafter		690

Total	$	10,186

Rental expense charged to operations was $5.1 million, $7.1 million and $6.8 million for the years ended December 31, 2005, 2004 and 2003, respectively.

NOTE 20: Contingencies

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

case. Decisions by the FERC on certain of the remanded issues were issued in 2005 and early 2006 and these decisions as well as the FERC policy on income taxes are the subject of petitions for review filed by us and certain other refining companies pending before the court of appeals. Rulings by the FERC on certain issues relating to periods after July 2000 have also been the subject of petitions by us and other refining companies for review by the court of appeals. Rulings by the FERC relating principally to the period from 1993 through July 2000 resulted in reparations payments from SFPP to us in 2003 totaling approximately $15.3 million. Because proceedings in the FERC on remand have not been completed and our petitions for review to the court of appeals with respect to the FERC’s orders are pending, it is not possible to determine whether the amount of reparations actually due to us for the period from 1993 through July 2000 will be found to be less than or more than the $15.3 million we received in 2003. Although it is not possible at the date of this report to predict the final outcome of these proceedings, we believe that future proceedings are not likely to result in an obligation for us to repay a significant portion of the reparations payments already received and could result in payment of additional reparations to us. The ultimate amount of reparations payable to us will be determined only after further proceedings in the FERC on issues that have not been finally determined by the FERC, further proceedings in the appeals court with respect to determinations by the FERC, and possibly future petitions by one or more of the parties seeking United States Supreme Court review of issues in the case.

In December 2001, we entered into an agreement for a Consent Decree (the “Consent Agreement”) with the Environmental Protection Agency (“EPA”), the New Mexico Environment Department and the Montana 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 refineries. The Consent Agreement was entered by the federal court in New Mexico in March 2002 and requires us to make investments at our New Mexico and Montana refineries for the installation of certain state of the art pollution control equipment currently expected to total approximately $15.0 million over a period expected to end in 2010, of which approximately $10.0 million has been expended. If the pending sale of the Montana Refinery is consummated, we will not be required to spend approximately $2.0 million (included in the $15.0 million total) for remaining investments at the Montana Refinery under the Consent Agreement. The Consent Agreement also provided for payment of penalties to Federal, New Mexico and Montana regulatory authorities in the total amount of $750,000, which were paid in fiscal 2002.

The EPA and the State of Utah have recently asserted that we have Clean Air Act 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 are currently assessing whether it will be feasible to settle the issues presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The EPA and Utah authorities have indicated that any such agreement in the case of the Woods Cross Refinery would likely involve undertakings by us to make specified capital investments and to make changes in operating procedures at the refinery as well as the payment of a penalty. 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. At the date of this report, it is not possible to predict whether we will be able to reach a mutually acceptable agreement with the EPA and Utah environmental authorities, what the terms of any agreement would be, what the outcome would be if the matter were resolved in a lawsuit brought by the EPA and Utah authorities, or what portion of claims asserted by the EPA and the Utah authorities would ultimately be paid by ConocoPhillips.

We are party to various other litigation and proceedings not mentioned in the Form 10-K which we believe, based on advice of counsel, will not have a materially adverse impact on our financial condition, results of operations or cash flows.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 21: Segment Information

Our operations are currently organized into one business division, Refining. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and NK Asphalt Partners. Our operations that are not included in the Refining business division include the operations of Holly Corporation, the parent company, and a small-scale oil and gas exploration and production program.

Prior to our deconsolidation of HEP effective July 1, 2005, our operations were organized into two business divisions, which were Refining and HEP. These segments have been in effect since July 13, 2004, the closing of the initial public offering of HEP. Our operations that were not included in either the Refining or HEP business divisions included the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program and the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us.

We reported results of operations in 2004 under the Refining segment prior to July 13, 2004 and our segments including HEP after July 13, 2004. The Refining segment presented in the 2004 Annual Report on Form 10-K is not the same Refining segment as presented below. The Refining segment presented below for the year ended December 31, 2004 includes results of operations involving certain assets currently included in HEP. We are not reporting any activity for HEP prior to July 13, 2004, as we did not restate the operations of the original segments prior to HEP’s formation date as it was not practical to do so. The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo Refinery, Montana Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Montana, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil pipelines (and intermediate product pipelines, prior to July 8, 2005 (see Note 2)) that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The Refining segment also includes the equity in earnings from our 49% interest in NK Asphalt Partners prior to February 2005. In February 2005, we acquired the remaining 51% interest in the asphalt joint venture from the other partner; subsequent to the purchase, we are including the operations of NK Asphalt Partners in our consolidated financial statements. NK Asphalt Partners, dba Holly Asphalt Company, manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and California. The cost of pipeline transportation and terminal services provided by HEP to us is also included in the Refining segment. The HEP segment involved all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of its pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain States. The HEP segment also included HEP’s 70% interest in Rio Grande, which provides petroleum products transportation. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande. Results of operations prior to July 13, 2004 involving the assets included in the HEP segment are included in the Refining segment for reporting purposes. Our operations not included in the two reportable segments are included in Corporate and Other, which includes costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations column included the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us. These items are no longer included after the deconsolidation of HEP on July 1, 2005.

The accounting policies for the segments, other than our accounting change due to the adoption of SFAS 123 (revised) (see Note 4), are the same as those described in the summary of significant accounting policies in our Annual Report on Form 10-K for the year ended December 31, 2005. Our reportable segments prior to July 1, 2005 were strategic business units that offered different products and services.

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


								Consolidations
					Corporate			and			Consolidated
	Refining		HEP		and Other			Eliminations			Total
					(In thousands)
Year Ended December 31, 2005
Sales and other revenues	$	3,194,767	$	36,034	$	1,772		$	(19,828	)	$	3,212,745
Depreciation and amortization	$	36,263	$	6,212	$	1,342		$	—		$	43,817
Income (loss) from operations	$	301,269	$	16,019	$	(49,786	)	$	—		$	267,502
Total assets	$	867,336	$	—	$	275,564		$	—		$	1,142,900

Year Ended December 31, 2004
Sales and other revenues	$	2,234,697	$	28,182	$	1,916		$	(18,422	)	$	2,246,373
Depreciation and amortization	$	35,809	$	3,241	$	1,431		$	—		$	40,481
Income (loss) from operations	$	175,441	$	12,980	$	(42,907	)	$	—		$	145,514
Total assets	$	580,092	$	103,758	$	219,395		$	79,468		$	982,713

Year Ended December 31, 2003
Sales and other revenues	$	1,394,436	$	—	$	9,258		$	(450	)	$	1,403,244
Depreciation and amortization	$	34,377	$	—	$	1,898		$	—		$	36,275
Income (loss) from operations	$	82,964	$	—	$	(22,897	)	$	—		$	60,067
Total assets	$	682,132	$	—	$	24,426		$	—		$	706,558

NOTE 22: Significant Customers

All revenues were domestic revenues, except for sales of gasoline and diesel fuel for export into Mexico by the Refining segment. The export sales were to an affiliate of PEMEX and accounted for approximately $82.0 million (3%) of our revenues in 2005, $48.7 million (2%) of revenues in 2004 and $57.0 million (4%) of revenues for 2003. In 2005, we had several significant customers, none of which accounted for more than 10% of our revenues. In 2004, significant sales of greater than 10% of revenues were made to one petroleum company by the Refining segment. This petroleum company accounted for $225.0 million (10%) and $163.0 million (12%) of revenues in 2004 and 2003, respectively. Another petroleum company accounted for $162.0 million (12%) of revenues in 2003.

NOTE 23: Other Income

On March 4, 2003, we sold our 400 mile Iatan crude oil gathering system located in West Texas to Plains All-American Pipeline, L.P. (“Plains”) for $24.0 million in cash. In connection with the transaction, we have entered into a six and a half year agreement with Plains that commits us to transport on that gathering system at an agreed upon tariff any crude oil we purchase in the relevant area of the Iatan system. The Iatan system, while profitable, was not considered central to our refining operations. The sale resulted in a pre-tax gain of $16.2 million. The proceeds from the sale increased our cash resources available for investment in our core refining operations, including our acquisition of the Woods Cross Refinery. The net gain on sale of assets of $15.8 million on the statement of income was reduced by the loss on sale of retail assets of $0.4 million described in Note 25.

In April 2003 and June 2003, we received reparations payments totaling approximately $15.3 million from SFPP. The payments were for claims brought by us and other parties before the FERC relating to tariffs of common carrier pipelines owned and operated by SFPP for shipments of refined products over several years from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. The final decision of the FERC is subject to judicial review. See Note 20 for additional information.

NOTE 24: Refinery and Retail Assets Acquisition

On June 1, 2003, we acquired from ConocoPhillips the Woods Cross Refinery, located near Salt Lake City, Utah, and related assets, including a refined products terminal in Spokane, Washington, and a 50% ownership interest in refined products terminals in Boise and Burley, Idaho for an agreed price of $25.0 million plus inventory less obligations assumed. At the time of acquisition, the Woods Cross Refinery had a crude oil capacity of 25,000

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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

BPSD. The purchase also included certain pipelines and other transportation assets used in connection with the refinery, 25 retail service stations located in Utah and Wyoming (which we sold in August 2003, see Note 25), and a 10 year exclusive license to market fuels under the Phillips brand in the states of Utah, Wyoming, Idaho and Montana. The total cash purchase price, including expenses and a $2.5 million deposit made in 2002, was $58.3 million. In accounting for the purchase, we recorded inventory of $35.5 million, property, plant and equipment of $25.6 million, intangible assets of $1.6 million and recorded a $4.4 million liability, principally for pension obligations.

NOTE 25: Sale of Woods Cross Retail Assets

In August 2003, we sold our retail assets located in Utah and Wyoming for $7.0 million, less our prorated share of property taxes and certain transaction expenses, plus $1.8 million for inventories, resulting in net cash proceeds of $8.5 million. The sale resulted in a pre-tax loss of approximately $0.4 million, due mainly to transaction expenses. The asset package included twenty five operating retail sites and three closed properties that we acquired from ConocoPhillips in June 2003 in the acquisition of the Woods Cross Refinery. We continue to supply the stations with fuel from our Woods Cross Refinery under a long-term supply agreement.

NOTE 26: Frontier Oil Lawsuit

The Final Order and Judgment (the “Order”) of the Delaware Court of Chancery in a lawsuit between Holly and Frontier Oil Corporation (“Frontier”) was issued in May 2005 and became final in June 2005. The lawsuit related to a 2003 merger agreement between the two companies. The Order, which is based on the court’s April 29, 2005 opinion in the case, provides that Frontier pay to us $1 in nominal damages and approximately $2,500 in actual court costs and filing fees and that we pay nothing to Frontier. Frontier has paid the amounts specified in the Order, neither party filed an appeal, and the time for filing an appeal has expired.

NOTE 27: Quarterly Information (Unaudited)


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Year
			(In thousands except share data)
Year Ended December 31, 2005
Sales and other revenues	$	651,725	$	771,296	$	935,279	$	854,445	$	3,212,745
Operating costs and expenses	$	624,886	$	683,480	$	841,909	$	794,968	$	2,945,243
Income from operations	$	26,839	$	87,816	$	93,370	$	59,477	$	267,502
Income before income taxes	$	22,176	$	84,121	$	97,367	$	64,749	$	268,413
Change in accounting principle (net of income tax expense of $426)	$	—	$	—	$	669	$	—	$	669
Net income	$	13,634	$	52,424	$	61,719	$	39,881	$	167,658
Net income per common share – basic	$	0.43	$	1.66	$	2.02	$	1.34	$	5.43
Net income per common share – diluted	$	0.42	$	1.62	$	1.97	$	1.31	$	5.30
Dividends per common share	$	0.08	$	0.10	$	0.10	$	0.10	$	0.38
Average number of shares of common stock outstanding
Basic		31,514		31,637		30,618		29,710		30,864
Diluted		32,195		32,359		31,386		30,496		31,622

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

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

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

There have been no events that occurred in the fourth quarter of 2005 that would need to be reported on Form 8-K that have not previously been reported.

PART III

Item 10. Directors and Executive Officers of the Registrant

The information required by Items 401, 405 and 406 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 11, 2006 and is incorporated herein by reference.

New York Stock Exchange Certification

In 2005, C. Lamar Norsworthy, III, as our Chief Executive Officer at the time, provided to the New York Stock Exchange the annual CEO certification regarding our compliance with the New York Stock Exchange’s corporate governance listing standards.

Item 11. Executive Compensation

The information required by Item 402 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 11, 2006 and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 11, 2006 and is incorporated herein by reference.

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HOLLY CORPORATION

INDEX TO EXHIBITS

Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K)


Exhibit
Number		Description

3.1		Restated Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3(a), of Amendment No. 1 dated December 13, 1988 to Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1988, File No. 1-3876).

3.2		By-Laws of Holly Corporation as amended and restated December 22, 2005 (incorporated by reference to Exhibit 3.2.2 of Registrant’s Current Report on Form 8-K filed December 22, 2005, File No. 1-3876).

4.1		Indenture, dated February 28, 2005, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).

4.2		Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).

4.3		Form of Notation of Guarantee (included as Exhibit E to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).

4.4		First Supplemental Indenture, dated March 10, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225).

4.5		Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified herein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005 , File No. 1-32225).

10.1*		Holly Corporation Stock Option Plan — As adopted at the Annual Meeting of Stockholders of Holly Corporation on December 13, 1990 (incorporated by reference to Exhibit 4(i) of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1991, File No. 1-3876).

10.2*		Holly Corporation Long-Term Incentive Compensation Plan as Amended and Restated (Formerly Designated the Holly Corporation 2000 Stock Option Plan) — As approved at the Annual Meeting of Stockholders of Holly Corporation on December 12, 2002 (incorporated by reference to Exhibit 10 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended October 31, 2002, File No. 1-3876).

10.3*		Supplemental Payment Agreement, dated as of July 8, 1993, between Lamar Norsworthy and Holly Corporation (incorporated by reference to Exhibit 10(a) of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1993, File No. 1-3876).

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Exhibit
Number		Description

10.4*		Holly Corporation – Supplemental Payment Agreement for 2001 Service as Director (incorporated by reference to Exhibit 10.19 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876).

10.5*		Holly Corporation – Supplemental Payment Agreement for 2002 Service as Director (incorporated by reference to Exhibit 10.20 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876).

10.6*		Holly Corporation – Supplemental Payment Agreement for 2003 Service as Director (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-3876).

10.7*		First Amendment to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated (formerly designated the Holly Corporation 2000 Stock Option Plan) (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005, File No. 1-3876).

10.8*		Form of Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.9*		Form of Executive Restricted Stock Agreement [two-year term vesting form] (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.10*		Form of Executive Restricted Stock Agreement [two-year term and performance vesting form] (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.11*		Form of Executive Restricted Stock Agreement [five-year term vesting form] (incorporated by reference to Exhibit 10.4 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.12*		Form of Executive Restricted Stock Agreement [five-year term and performance vesting form] (incorporated by reference to Exhibit 10.5 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.13*		Form of Performance Share Unit Agreement [one-year form] (incorporated by reference to Exhibit 10.6 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.14*		Form of Performance Share Unit Agreement [three-year form] (incorporated by reference to Exhibit 10.7 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

10.15*		Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed August 4, 2005, File No. 1-3876).

10.16*		Form of Amendment to Performance Share Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 10, 2006, File No. 1-3876).

10.17		Asset Purchase and Sale Agreement between Phillips Petroleum Company as Seller and Holly Corporation as Buyer Dated as of December 20, 2002 (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-3876).

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Exhibit
Number		Description

10.18		Contribution Agreement, dated January 25, 2005, among Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., T&R Assets, Inc., Alon USA Refining, Inc., Alon Pipeline Assets, LLC, Alon Pipeline Logistics, LLC, Alon USA, Inc. and Alon USA, LP (incorporated by reference to Exhibit 2.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed January 31, 2005, File No. 1-32225).

10.19		Purchase and Sale Agreement, dated July 6, 2005 by and among Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.P., Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P. and HEP Pipeline, L.L.C. (incorporated by reference to Exhibit 2.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed with the SEC on July 12, 2005, File No. 1-32225).

10.20		Credit Agreement, dated as of July 1, 2004, among Holly Corporation, as borrower, Bank of America, N.A. as Administrative Agent and L/C Issuer, Guaranty Bank and PNC Bank, National Association as Co-Documentation Agents, Union Bank of California, N.A. as syndication Agent, The Other lenders Party Hereto, and Banc of America Securities LLC, as Lead Arranger and Sole Book Manager (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-3876).

10.21		The First Amendment and Waiver dated as of January 25, 2005 and entered into by and between Holly Corporation, each of the lenders, and Bank of America, N.A., in its capacity as the Administrative Agent for the lenders under the Credit Agreement (incorporated by reference to Exhibit 99.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, File No. 1-3876).

10.22		The Second Amendment dated as of May 17, 2005 and entered into by and between Holly Corporation, each of the lenders, and Bank of America, N.A., in its capacity as the Administrative Agent for the lenders under the Credit Agreement (incorporated by reference to Exhibit 99.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, File No. 1-3876).

10.23+		The Third Amendment dated as of December 23, 2005 and entered into by and between Holly Corporation, each of the lenders, and Bank of America, N.A., in its capacity as the Administrative Agent for the lenders under the Credit.

10.24		Guarantee and Collateral Agreement, dated as of July 1, 2004, among Holly Corporation and certain of its Subsidiaries in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-3876).

10.25		Credit Agreement, dated as of July 7, 2004, among HEP Operating Company, L.P., as borrower, the financial institutions party to this agreement, as banks, Union Bank of California, N.A., as administrative agent and sole lead arranger, Bank of America, National Association, as syndication agent, and Guaranty Bank, as documentation agent (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

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										Five Months			Fiscal Year			Five Months			Fiscal Year
										Ended			Ended			Ended			Ended
	Years Ended December 31,									December 31,			July 31,			December 31,			July 31,
	2005			2004			2003			2002			2002			2001			2001
	(In thousands, except per share data)
FINANCIAL DATA
For the period
Sales and other revenues	$	3,212,745		$	2,246,373		$	1,403,244		$	448,637		$	888,906		$	363,854		$	1,142,130
Income before income taxes	$	268,413		$	138,469		$	74,359		$	8,517		$	50,896		$	30,429		$	121,895
Income tax provision		101,424			54,590			28,306			3,114			18,867			11,822			48,445

Income before change in accounting principle		166,989			83,879			46,053			5,403			32,029			18,607			73,450
Change in accounting principle (net of income tax expense of $426)		669			—			—			—			—			—			—


Net income	$	167,658		$	83,879		$	46,053		$	5,403		$	32,029		$	18,607		$	73,450


Net income per common share – basic	$	5.43		$	2.67		$	1.49		$	0.17		$	1.03		$	0.60		$	2.42

Net income per common share – diluted	$	5.30		$	2.61		$	1.44		$	0.17		$	1.00		$	0.58		$	2.39

Cash dividends declared per common share	$	0.38		$	0.29		$	0.22		$	0.055		$	0.205		$	0.05		$	0.185

Average number of common shares outstanding:
Basic		30,864			31,390			31,010			31,032			31,120			31,048			30,374
Diluted		31,622			32,170			32,032			31,804			31,942			31,898			30,774

Net cash provided by (used for) operating activities	$	251,234		$	164,604		$	75,440		$	(8,209	)	$	53,951		$	7,085		$	112,463
Net cash used for investing activities	$	(320,135	)	$	(194,003	)	$	(122,714	)	$	(25,293	)	$	(33,603	)	$	(5,905	)	$	(34,445	)
Net cash provided by (used for) financing activities	$	50,505		$	85,169		$	34,698		$	(13,862	)	$	(14,558	)	$	(10,387	)	$	(15,806	)

At end of period
Cash, cash equivalents and investments in marketable securities	$	254,842		$	219,265		$	11,690		$	24,266		$	71,630		$	56,633		$	65,840
Working capital	$	198,562		$	148,642		$	(27,140	)	$	12,445		$	59,873		$	52,168		$	57,731
Total assets	$	1,142,900		$	982,713		$	706,558		$	515,793		$	502,306		$	464,273		$	490,429
Total debt, including current maturities and borrowings under credit agreements	$	—		$	33,572		$	67,142		$	25,714		$	34,285		$	37,315		$	42,857
Stockholders’ equity	$	377,351		$	339,916		$	286,609		$	228,494		$	228,556		$	217,961		$	201,734


			Payments Due by Period
			Less than						Over
	Total		1 Year		2-3 Years		4-5 Years		5 Years
Contractual Obligations	(In thousands)
Operating leases	$	10,186	$	2,510	$	4,160	$	2,826	$	690
Minimum revenue agreements with HEP	$	666,719	$	48,511	$	97,021	$	97,021	$	424,166


Item		Page
	PART I

Forward-Looking Statements		3

Definitions		4

1 & 2.	Business and properties	7
1A.	Risk factors	23
1B.	Unresolved staff comments	29
3.	Legal proceedings	29
4.	Submission of matters to a vote of security holders	30

	PART II

5.	Market for the Registrant’s common equity and related stockholder matters	31
6.	Selected financial data	33
7.	Management’s discussion and analysis of financial condition and results of operations	34
7A.	Quantitative and qualitative disclosures about market risk	54

Reconciliations to amounts reported under generally accepted accounting principles		54

8.	Financial statements and supplementary data	61
9.	Changes in and disagreements with accountants on accounting and financial disclosure	98
9A.	Controls and procedures	98
9B.	Other information	98

	PART III

10.	Directors and executive officers of the Registrant	98
11.	Executive compensation	98
12.	Security ownership of certain beneficial owners and management and related stockholder matters	98
13.	Certain relationships and related transactions	99
14.	Principal Accountant fees and services	99

	PART IV

15.	Exhibits and financial statements schedules	100

Signatures		101

Index to exhibits		103
3rd Amendment as Administrative Agent
Subsidiaries
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


	Page
	Reference
Alon		11
ARS		43
CAA		21
CARB		14
CERCLA		22
Connacher		8
Consent Agreement		21
CWA		22
DESC		14
EBITDA		37
EPA		14
Exchange Act		98
FASB		7
FERC		29
FIN		7
FINA		20
Frontier		35
HEP		7
HEP IPA		19
HEP PTA		18
HEP Senior Notes		41
Koch		11
Leased Pipeline		13
Longhorn Partners		12
LIFO		39
MACT		16
Magellan		12
Montana Refinery		8
MRC		29
Navajo Refinery		7
NPDES		22
Order		35
PEMEX		9
Plains		13
RCRA		22
Rio Grande		7
SEC		7
SDWA		22
SFAS		41
SFPP		11
VCU		29
VIE		34
VRDN		43
Woods Cross Refinery		7


	Page
	Reference
Report of Independent Registered Public Accounting Firm		64

Consolidated Balance Sheets at December 31, 2005 and 2004		65

Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003		66

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		67

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		68

Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003		69

Notes to Consolidated Financial Statements		70


									Accumulated
									Other						Total
	Common		Additional			Retained			Comprehensive			Treasury			Stockholders’
	Stock		Capital			Earnings			Income (Loss)			Stock			Equity
	(In thousands)
Balance at December 31, 2002	$	168	$	15,221		$	225,759		$	(1,049	)	$	(11,605	)	$	228,494
Net income		—		—			46,053			—			—			46,053
Dividends		—		—			(6,821	)		—			—			(6,821	)
Other comprehensive income		—		—			—			1,179			—			1,179
Issuance of common stock upon exercise of stock options		1		368			—			—			—			369
Tax benefit from stock options		—		229			—			—			—			229
Purchase of treasury stock		—		—			—			—			(894	)		(894	)


Balance at December 31, 2003	$	169	$	15,818		$	264,991		$	130		$	(12,499	)	$	268,609
Net income		—		—			83,879			—			—			83,879
Dividends		—		—			(9,072	)		—			—			(9,072	)
Other comprehensive loss		—		—			—			(1,849	)		—			(1,849	)
Issuance of common stock upon exercise of stock options		6		4,649			—			—			—			4,655
Tax benefit from stock options		—		5,568			—			—			—			5,568
Issuance of restricted stock, net of forfeitures		—		3,419			—			—			—			3,419
Purchase of treasury stock		—		—			—			—			(15,293	)		(15,293	)
Two-for-one stock split		173		(173	)		—			—			—			—


Balance at December 31, 2004	$	348	$	29,281		$	339,798		$	(1,719	)	$	(27,792	)	$	339,916
Net income		—		—			167,658			—			—			167,658
Dividends		—		—			(11,637	)		—			—			(11,637	)
Other comprehensive loss		—		—			—			(3,083	)		—			(3,083	)
Issuance of common stock upon exercise of stock options		6		2,776			—			—			—			2,782
Tax benefit from stock options		—		5,815			—			—			—			5,815
Amortization of stock options		—		468			—			—			—			468
Issuance of restricted stock, net of forfeitures		—		2,503			—			—			—			2,503
Tax benefit from restricted stock		—		411			—			—			—			411
Purchase of treasury stock		—		—			—			—			(130,763	)		(130,763	)
Sale of treasury stock		—		2,090			—			—			1,191			3,281


Balance at December 31, 2005	$	354	$	43,344		$	495,819		$	(4,802	)	$	(157,364	)	$	377,351


	December 31, 2005
	Assets		Liabilities			Total
			(In thousands)
Deferred taxes
Accrued employee benefits	$	4,218	$	(30	)	$	4,188
Accrued postretirement benefits		143		(1,337	)		(1,194	)
Accrued environmental costs		418		—			418
Inventory differences		634		(3,235	)		(2,601	)
Deferred turnaround costs		—		(2,562	)		(2,562	)
Prepayments and other		729		(1,001	)		(272	)

Total current		6,142		(8,165	)		(2,023	)
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(59,663	)		(59,663	)
Accrued postretirement benefits		6,649		—			6,649
Accrued environmental costs		782		—			782
Deferred turnaround costs		—		(2,873	)		(2,873	)
Investments in HEP		39,803		(376	)		39,427
Other		4,482		(859	)		3,623

Total noncurrent		51,716		(63,771	)		(12,055	)

Total	$	57,858	$	(71,936	)	$	(14,078	)


	December 31, 2004
	Assets		Liabilities			Total
	(In thousands)
Deferred taxes
Accrued employee benefits	$	2,900	$	(30	)	$	2,870
Accrued postretirement benefits		273		(11	)		262
Accrued environmental costs		474		—			474
Inventory differences		634		(1,513	)		(879	)
Deferred turnaround costs		—		(3,572	)		(3,572	)
Pipeline lease		223		—			223
Prepayments and other		1,450		(1,802	)		(352	)

Total current		5,954		(6,928	)		(974	)
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(20,470	)		(20,470	)
Accrued postretirement benefits		2,836		—			2,836
Accrued environmental costs		927		—			927
Deferred turnaround costs		—		(4,761	)		(4,761	)
Investments in joint ventures		34		(399	)		(365	)
Pipeline lease		228		—			228
Other		2,104		(961	)		1,143

Total noncurrent		6,129		(26,591	)		(20,462	)

Total	$	12,083	$	(33,519	)	$	(21,436	)


				Tax Expense
	Before-Tax			(Benefit)			After-Tax
				(In thousands)
For the year ended December 31, 2005
Minimum pension liability adjustment	$	(4,973	)	$	(1,934	)	$	(3,039	)
Unrealized loss on available for sale securities		(72	)		(28	)		(44	)

Other comprehensive loss	$	(5,045	)	$	(1,962	)	$	(3,083	)


For the year ended December 31, 2004
Minimum pension liability adjustment	$	(2,006	)	$	(783	)	$	(1,223	)
Unrealized loss on available for sale securities		(419	)		(162	)		(257	)
Hedging activities		(599	)		(230	)		(369	)

Other comprehensive loss	$	(3,024	)	$	(1,175	)	$	(1,849	)


For the year ended December 31, 2003
Minimum pension liability adjustment	$	1,362		$	523		$	839
Hedging activities		552			212			340

Other comprehensive income	$	1,914		$	735		$	1,179


	Page in
	Form 10-K
Report of Independent Registered Public Accounting Firm		64

Consolidated Balance Sheets at December 31, 2005 and 2004		65

Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003		66

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		67

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		68

Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003		69

Notes to Consolidated Financial Statements		70


	HOLLY CORPORATION (Registrant)
	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chief Executive Officer


Signature	Capacity	Date

/s/ C. Lamar Norsworthy, III C. Lamar Norsworthy, III	Chairman of Board	March 7, 2006

/s/ Matthew P. Clifton Matthew P. Clifton	Chief Executive Officer and Director	March 7, 2006

/s/ P. Dean Ridenour P. Dean Ridenour	Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 7, 2006

/s/ Stephen J. McDonnell Stephen J. McDonnell	Vice President and Chief Financial Officer (Principal Financial Officer)	March 7, 2006

/s/ W. John Glancy W. John Glancy	Senior Vice President, General Counsel and Director	March 7, 2006

/s/ Buford P. Berry Buford P. Berry	Director	March 7, 2006

/s/ William J. Gray William J. Gray	Director	March 7, 2006


+		Filed herewith.

*		Constitutes management contracts or compensatory plans or arrangements.

	(d)		Section 7.05 is further amended by deleting the reference to “clauses (a) through (g)” in the last line thereof and replacing it with “clauses (a) through (h)”.

	(e)		Section 7.06(d) is amended by (i) deleting each reference therein to “March 31, 2005” and replacing it with “September 30, 2005” and (ii) deleting the word “and” at the end thereof.

	(f)		Section 7.06 is amended by (i) deleting the “.” at the end of clause (e) thereof and replacing it with “; and” and (ii) adding a new clause (f) as follows:

	“(f) the Borrower may purchase, redeem or acquire shares of its common stock, $.01 par value per share, pursuant to the Secondary Share Repurchase Program; provided that immediately after giving effect to such proposed action, no Default would exist.”

	(g)		Section 7.11(a) is amended by adding the following at the end of such section:

	“and the Secondary Share Repurchase Program”.


BORROWER: HOLLY CORPORATION, a Delaware corporation, as Borrower
By:	/s/ Stephen D. Wise
	Name:	Stephen D. Wise
	Title:	Treasurer


ADMINISTRATIVE AGENT: BANK OF AMERICA, N.A., in its capacity as Administrative Agent for and on behalf of the Lenders
By:	/s/ Claire Liu
	Name:	Claire Liu
	Title:	Senior Vice President


LENDERS: BANK OF AMERICA, N.A., as a Lender
By:	/s/ Claire Liu
	Name:	Claire Liu
	Title:	Senior Vice President


PNC BANK, NATIONAL ASSOCIATION, as a Lender
By:	/s/ Marc Muehlemann
	Name:	Marc Muehlemann
	Title:	Vice President


GUARANTY BANK, as a Lender
By:	/s/ Jim R. Hamilton
	Name:	Jim R. Hamilton
	Title:	Senior Vice President


UNION BANK OF CALIFORNIA, N.A., as a Lender
By:	/s/ Sean Murphy
	Name:	Sean Murphy
	Title:	Vice President


REGIONS BANK, as a Lender
By:	/s/ Jated Andersen
	Name:	Jated Andersen
	Title:	Vice President


RZB FINANCE LLC,
as a Lender

By:	/s/ John A. Valiska	By:	/s/ Christoph Hoedl

	Name: JOHN A. VALISKA		Name: CHRISTOPH HOEDL
	Title: First Vice President		Title: Group Vice President


U.S. BANK NATIONAL ASSOCIATION, as a Lender
By:	/s/ Mark E. Thompson
	Name:	Mark E. Thompson
	Title:	Vice President


WELLS FARGO BANK, N.A., as a Lender
By:	/s/ M. Jarrod Bourgeois
	Name:	M. Jarrod Bourgeois
	Title:	Assistant Vice President


		State of
		Incorporation
Name of Entity		or Organization
Black Eagle, Inc.		Delaware
Holly Logistics Services, L.L.C.		Delaware
HEP Logistics Holdings, L.P.		Delaware
Holly Petroleum, Inc.		Delaware
Holly Payroll Services, Inc.		Delaware
Holly Pipeline, L.L.C.		Delaware
Holly Refining & Marketing Company		Delaware
Holly Refining & Marketing Company – Woods Cross		Delaware
Holly Refining Communications, Inc.		Delaware
Holly Utah Holdings, Inc.		Delaware
Holly Western Asphalt Company		Deleware
Lea Refining Company		Delaware
Lorefco, Inc.		Delaware
Montana Refining Company, a Partnership ⁽¹⁾		Montana
Montana Retail Corporation		Delaware
Navajo Crude Oil Purchasing, Inc.		New Mexico
Navajo Holdings, Inc.		New Mexico
Navajo Northern, Inc.		Nevada
Navajo Pipeline Co., L.P. ⁽²⁾		Delaware
Navajo Pipeline GP, L.L.C.		Delaware
Navajo Pipeline LP, L.L.C.		Delaware
Navajo Refining Company, L.P. ⁽³⁾		Delaware
Navajo Refining GP, L.L.C.		Delaware
Navajo Refining LP, L.L.C.		Delaware
Navajo Western Asphalt Company		New Mexico
NK Asphalt Partners ⁽⁵⁾		New Mexico
Woods Cross Refining Company, L.L.C. ⁽⁴⁾		Delaware


(1)		Montana Refining Company, a Partnership also does business as Montana Refining Company.

(2)		Navajo Pipeline Co., L.P. also does business as Navajo Pipeline Co.

(3)		Navajo Refining Company, L.P. also does business as Navajo Refining Company.

(4)		Woods Cross Refining Company, L.L.C. does business as Holly Refining & Marketing Company – Woods Cross.

(5)		NK Asphalt Partners does business as Holly Asphalt Company.



Date: March 7, 2006	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chief Executive Officer



Date: March 7, 2006	/s/ Stephen J. McDonnell
	Stephen J. McDonnell
	Vice President and Chief Financial Officer