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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934:

For the fiscal year ended December 31, 2004

Commission File Number 1-3876

HOLLY CORPORATION

Incorporated under the laws of the State of Delaware

I.R.S. Employer Identification No. 75-1056913

100 Crescent Court, Suite 1600
Dallas, Texas 75201-6927
Telephone number: (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 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 and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes þ No o

On June 30, 2004 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $402,000,000. (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.)

31,591,382 shares of Common Stock, par value $.01 per share, were outstanding on February 16, 2005.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 9, 2005, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2004, are incorporated by reference in Part III.

 
 

 


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 Subsidiaries of Registrant
 Consent of Independent Registered Public Accounting Firm
 Certification of CEO Pursuant to Section 302
 Certification of CFO Pursuant to Section 302
 Certification of CEO Pursuant to Section 906
 Certification of CFO Pursuant to Section 906

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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, “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 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 successfully purchase and integrate any future acquired operations;
 
  •   the outcome of litigation with Frontier Oil Corporation;
 
  •   the ability of Holly Energy Partners, L.P. to successfully integrate its recent acquisition of assets from Alon USA, Inc.;
 
  •   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 SEC 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. 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.

     “Fluid catalytic cracking (“FCC”)” 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.

     “Hydrofluoric (“HF”) alkylation” means a refinery process which combines isobutane and C3 / C4 olefins using HF acid as a catalyst to make high octane gasoline blendstock.

     “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.

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

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

     “Refining gross margin” or “refinery gross margin” means the difference between average net sales price and average raw material costs per barrel of produced refined products. This does not include the associated depreciation, depletion and amortization costs.

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

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

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     “Sour crude oil” means crude oil containing quantities of hydrogen sulfur greater than 0.4%, while “sweet crude oil” would contain quantities of hydrogen sulfur less than 0.4%.

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

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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 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 Controller at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission (“SEC”) web site is available on our website on the Investors Relations 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 Controller 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 an initial public offering of limited partnership interests in Holly Energy Partners, L.P. (“HEP”); a Delaware limited partnership which is currently owned 47.9% by us and 52.1% by other investors in HEP. We consolidate the results of HEP and show the interest we do not own as a minority interest in ownership and earnings.

      As of December 31, 2004, following the initial public offering of HEP, 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 1,000 miles of crude oil and intermediate product pipelines located principally in West Texas and New Mexico;
 
  •   owned a 49% interest in NK Asphalt Partners (our current ownership interest is 100% due to our acquisition of the other partner’s interest as discussed below), which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and
 
  •   owned a 51% interest in HEP (our current ownership interest is 47.9% due to the asset acquisition from Alon USA, Inc. as discussed below), which owns logistics assets including approximately 780 miles of refined product pipelines located principally in West Texas and New Mexico (including 340 miles of leased pipeline); nine refined product terminals; and a 70% interest in Rio Grande Pipeline Company (“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 (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. In June 2003, we acquired the Woods Cross Refinery from ConocoPhillips. The 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 our wholly-owned subsidiaries. This facility is a high conversion refinery that processes regional sweet (lower sulfur) 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 1,000 miles of pipelines that serve primarily as the supply and distribution network for our refineries.

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At December 31, 2004, HEP owned assets including approximately 780 miles of refined product pipelines located principally in West Texas and New Mexico (including 340 miles of leased pipeline); nine refined product terminals (three of which are owned 50% by HEP and 50% by unaffiliated parties) in Albuquerque, Moriarty and Bloomfield, New Mexico; Tucson, Arizona; El Paso, Texas; Burley and Boise, Idaho; Spokane, Washington; and Mountain Home, Idaho; and a 70% interest in Rio Grande, which owns a 249-mile pipeline that transports LPG’s from west Texas to the Texas/Mexico border near El Paso for further transport into Northern Mexico. On February 28, 2005, HEP closed on its acquisition from Alon USA, Inc. and certain of its affiliates (collectively “Alon”) of over 500 miles of light products pipelines and two light product terminals for $120.0 million in cash and 937,500 HEP Class B subordinated units which will convert into an equal number of HEP common units in five years. As a result of the closing of this transaction, we now own 47.9% of HEP, including the 2% general partner interest, and other investors in HEP own 52.1%. In connection with the transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon.

In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by Koch Materials Company for $16.9 million plus working capital. This purchase increased our ownership in NK Asphalt Partners from 49% to 100%. The partnership manufactures and markets asphalt and asphalt products in Arizona and New Mexico and now does business under the name of “Holly Asphalt Company.”

Our operations are currently organized into two business divisions, which are Refining and HEP. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and our interest in NK Asphalt Partners. Our operations that are not included in either the Refining or HEP business divisions include 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 our pipeline transportation services between us and HEP as well as the elimination of our minority interest in income of HEP.

On July 30, 2003, we changed our fiscal year-end from July 31 to December 31. In connection with this change and accordance with SEC rules, on September 12, 2003, a Form 10-Q transition report was filed for the five month period ended December 31, 2002. The different fiscal year periods reported in this Annual Report on Form 10-K are due to our change in year-end.

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 about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation, depletion and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts under Generally Accepted Accounting Principles” following Item 7A 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.

                                         
                    Five Months     Fiscal Year     Five Months  
    Years Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003 (8)     2002     2002     2001  
Consolidated
                                       
Crude charge (BPD) (1)
    102,230       76,040       64,270       60,200       54,480  
Refinery production (BPD) (2)
    111,070       85,030       72,280       66,360       59,740  
Sales of produced refined products (BPD)
    110,370       82,900       70,490       67,060       60,580  
Sales of refined products (BPD) (3)
    118,760       95,420       82,260       76,420       73,310  
 
                                       
Refinery utilization (4)
    94.7 %     93.2 %     95.9 %     89.9 %     81.3 %

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                    Five Months     Fiscal Year     Five Months  
    Years Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003 (8)     2002     2002     2001  
Average per produced barrel (5)
                                       
Net sales
  $ 50.80     $ 38.99     $ 34.65     $ 30.95     $ 31.71  
Cost of products (6)
    41.70       31.76       29.10       24.22       23.72  
 
                             
Refinery gross margin
    9.10       7.23       5.55       6.73       7.99  
Refinery operating expenses (7)
    3.53       3.58       3.09       3.13       3.47  
 
                             
Net operating margin
  $ 5.57     $ 3.65     $ 2.46     $ 3.60     $ 4.52  
 
                             
 
                                       
Feedstocks:
                                       
Sour crude oil
    67 %     66 %     77 %     77 %     77 %
Sweet crude oil
    23 %     23 %     10 %     12 %     12 %
Other feedstocks and blends
    10 %     11 %     13 %     11 %     11 %
 
                             
Total
    100 %     100 %     100 %     100 %     100 %
 
                             


(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity.
 
(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 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.

                                         
                    Five Months     Fiscal Year     Five Months  
    Years Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
Consolidated
                                       
Sales of produced refined products:
                                       
Gasolines
    58 %     57 %     57 %     56 %     54 %
Diesel fuels
    27 %     23 %     21 %     21 %     21 %
Jet fuels
    4 %     8 %     10 %     11 %     11 %
Asphalt
    7 %     8 %     8 %     9 %     11 %
LPG and other
    4 %     4 %     4 %     3 %     3 %
 
                             
Total
    100 %     100 %     100 %     100 %     100 %
 
                             

Approximately 2% of our revenues in 2004 resulted from the sale for export of gasoline and diesel fuel to an affiliate of Pemex Gas (“Pemex”), the government-owned energy company of Mexico. Approximately 4% of our revenues in 2004 resulted from the sale of military jet fuel to the United States Government. The loss of our

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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 cannot be secured. In addition to the United States Government and Pemex, other significant sales were made to two petroleum companies. BP West Coast Products, LLC purchases our gasoline to supply its retail network and accounted for approximately 10% of our revenues in 2004. During most of 2004, ConocoPhillips purchased our gasoline to supply its branded retail network in Arizona and accounted for approximately 7% of our revenues in 2004. In late 2004, ConocoPhillips sold their retail stations that we had supplied in the Arizona market. We have continued to supply gasoline for a substantial portion of these stations following the sale but at a volume somewhat lower than prior to the sale. Loss of, or reduction in amounts purchased by, our major customers that purchase for their retail operations could have a material 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 is our ability to connect new supplies of crude oil to our gathering systems or to our other crude oil receiving lines, our success in contracting for and receiving existing crude oil supplies that are currently being purchased by other refineries, and the level of drilling activity near our gathering systems or our other crude oil receiving lines.

Navajo Refinery

Facilities
The Navajo Refinery has a crude oil capacity of 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 2004, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 59%, 26% and 5%, 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.

                                         
                    Five Months     Fiscal Year     Five Months  
    Years Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
Navajo Refinery
                                       
Crude Charge (BPD) (1)
    71,060       56,080       57,510       53,640       47,930  
Refinery production (BPD) (2)
    79,330       63,680       65,150       59,390       52,760  
Sales of produced refined products (BPD)
    78,880       62,570       63,400       59,830       52,820  
Sales of refined products (BPD) (3)
    86,410       74,500       74,360       68,880       65,250  
 
                                       
Refinery utilization (4)
    94.7 %     93.5 %     95.9 %     89.4 %     79.9 %
 
                                       
Average per produced barrel (5)
                                       
Net sales
  $ 51.42     $ 38.95     $ 34.93     $ 31.02     $ 31.75  
Cost of products (6)
    41.26       31.52       29.44       24.46       23.92  
 
                             
Refinery gross margin
    10.16       7.43       5.49       6.56       7.83  
Refinery operating expenses (7).
    3.20       3.24       2.81       2.84       3.20  
 
                             
Net operating margin
  $ 6.96     $ 4.19     $ 2.68     $ 3.72     $ 4.63  
 
                             
 
                                       
Feedstocks:
                                       
Sour crude oil
    83 %     78 %     75 %     75 %     75 %
Sweet crude oil
    5 %     10 %     11 %     13 %     13 %
Other feedstocks and blends
    12 %     12 %     14 %     12 %     12 %
 
                             
Total
    100 %     100 %     100 %     100 %     100 %
 
                             

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(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refinery.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refinery.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity.
 
(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, included in cost of products are transportation costs billed from HEP.
 
(7)   Represents operating expenses of our 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, fluid catalytic cracking (“FCC”), 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, 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 facilities are operated in conjunction with integrated refining facilities located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at Lovington refinery 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 processes crude oil into intermediate products, which are transported to Artesia by means of two of our owned pipelines, and which are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Artesia / Lovington facilities is 75,000 BPSD and typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, and gas oil.

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, 67 crude oil trucks and 70 trailers, and over 600,000 barrels of related tankage.

We distribute refined products from the Navajo Refinery to markets in Arizona, Albuquerque and West Texas primarily through two of HEP’s owned pipelines that extend from Artesia to El Paso. 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%. All asphalt produced at the Navajo Refinery is sold at market prices to NK Asphalt Partners under a supply agreement. Following the purchase of the 51% interest from Koch, NK Asphalt Partners now does business under the name of “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 from El Paso 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 began transporting petroleum products in late 1999 to

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markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via a leased pipeline 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 are 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. Holly Corporation or HEP (subsequent to July 13, 2004) receives monthly payments from Alon in the amount of $536,000 with respect to a long term lease of the pipeline, subject to periodic rent adjustments.

The El Paso market for refined products is currently supplied by a number of refiners either that are located in El Paso or that 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 ship approximately 54,000 BPD into the El Paso market, 11,000 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 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, 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. In December 2003, the United States Court of Appeals for the Fifth Circuit affirmed the decision by the federal district court in Austin, Texas that allowed the Longhorn Pipeline to begin operations when agreed improvements had been completed. In October 2004, the Supreme Court of the United States denied review of the Court of Appeals decision. It is our understanding that there have been some limited shipments of refined products on the Longhorn Pipeline in recent months.

The Longhorn Pipeline could result in downward pressure on wholesale refined products margins in El Paso and related markets. 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

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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 has announced plans to expand the capacity of its pipeline from El Paso to the Arizona market by between 45,000 and 50,000 BPD. According to industry sources, this expansion is expected to be completed during the second quarter of 2006. Although our results of operations might be adversely impacted by the Longhorn Pipeline and by the expansion 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.

In November 2002, as a result of our settlement of litigation with Longhorn Partners, we prepaid $25.0 million to Longhorn Partners for the shipment of 7,000 BPD of refined products from the Gulf Coast to El Paso in a period of up to six years from the date the Longhorn Pipeline begins operations if such operations began by July 1, 2004. Under the agreement, the prepayment would have covered shipments of 7,000 BPD for approximately four and a half years assuming there were no curtailments of service once operations began. On July 1, 2004, under the terms of the November 2002 settlement agreement that terminated litigation between us and Longhorn Partners, we received $25.0 million principal plus $2.2 million of interest from Longhorn Partners. This repayment resulted in a termination of our prepaid transportation rights under the November 2002 settlement agreement.

Arizona and Albuquerque Markets
We currently supply approximately 33,000 BPD of refined products into the Arizona market, which is comprised primarily of Phoenix and Tucson, which accounts for approximately 14% of the refined products consumed in that market. We currently ship approximately 11,000 BPD of refined products into the Albuquerque 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 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 by between 45,000 and 50,000 BPD. According to industry sources, this expansion is expected to be completed during the second quarter of 2006. 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 of the proposed pipeline expansion on us.

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 an option to renew for an additional ten years. 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

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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. The sale resulted in a pre-tax gain of $16.2 million. 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 2004, approximately 4,000 BPD of isobutane and 4,000 to 4,500 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 our 65-mile pipeline 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:

                                         
                    Five Months     Fiscal Year     Five Months  
    Years Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
Navajo Refinery
                                       
Sales of produced refined products:
                                       
Gasolines
    59 %     58 %     58 %     58 %     57 %
Diesel fuels
    26 %     23 %     22 %     22 %     22 %
Jet fuels
    5 %     9 %     11 %     11 %     11 %
Asphalt
    6 %     7 %     6 %     6 %     7 %
LPG and other
    4 %     3 %     3 %     3 %     3 %
 
                             
Total
    100 %     100 %     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 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. Since the formation of NK Asphalt Partners in July 2000, all asphalt from the Navajo Refinery has been sold to NK Asphalt Partners (now doing business as Holly Asphalt Company). 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 4,200 BPD of jet fuel to the DESC in 2004. We had a military jet fuel supply contract with the United States Government for each of the last 35 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 August 2004, DESC awarded us contracts for sales of military jet fuel for the period October 1, 2004 through September 30, 2005. Our total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, was approximately 63 million gallons as compared to the total award for the 2003-2004 contract year of approximately 85 million gallons.

Capital Improvement Projects

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

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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 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.

For the 2005 year, our capital budget for the Navajo Refinery totals $60.3 million for various refining improvement projects. Additionally, $6.5 million was approved in the 2005 capital budget for pipeline and other transportation related projects.

Our combined 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 ultra low sulfur diesel (“ULSD”) service, the expansion of the continuous catalytic reformer and the conversion of the kerosene hydrotreater to naphtha service, which will allow us to produce ULSD by June 2006. Additionally, we plan to revamp our crude and vacuum units at Artesia and Lovington for improved energy conservation and cutpoints which will also permit us to increase our processing up to 85,000 BPSD of crude. We estimate the total cost to complete the ULSD project and expansion of our crude oil refining capacity to 85,000 BPSD at $52 million and plan for completion in 2006. It is currently anticipated that these projects will also permit the Navajo Refinery without substantial additional investment to comply with low-sulfur gasoline (“LSG”) requirements that will become applicable in 2010.

We have purchased and plan to relocate and refurbish an existing 4,500 BPSD ROSE asphalt unit for the Navajo Refinery at a total estimated cost of $16.4 million. This project will upgrade asphalt to higher valued gasoline and diesel and is expected to be operational in the first quarter of 2006.

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, 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 (which were sold in August 2003), 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 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 sales resulted in a pre-tax loss of approximately $0.4 million, due principally to transaction expenses. The asset package included the 25 operating retail sites and three closed properties acquired from ConocoPhillips in the Woods Cross refinery acquisition. We continue to supply the retail stations with fuel from our Woods Cross Refinery under a long-term supply agreement.

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The Woods Cross Refinery is being operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly owned subsidiaries. Beginning January 1, 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 on June 1, 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,  
    2004     2003 (8)  
Woods Cross Refinery
               
Crude Charge (BPD) (1)
    23,620       22,540  
Refinery production (BPD) (2)
    23,730       23,870  
Sales of produced refined products (BPD)
    23,520       22,480  
Sales of refined products (BPD) (3)
    24,160       22,680  
 
               
Refinery utilization (4)
    94.5 %     90.2 %
 
               
Average per produced barrel (5)
               
Net sales
  $ 51.33     $ 40.91  
Cost of products (6)
    45.33       34.81  
 
           
Refinery gross margin
    6.00       6.10  
Refinery operating expenses (7)
    3.92       3.92  
 
           
Net operating margin
  $ 2.08     $ 2.18  
 
           
 
               
Feedstocks:
               
Sour crude oil
    7 %     1 %
Sweet crude oil
    88 %     94 %
Other feedstocks and blends
    5 %     5 %
 
           
Total
    100 %     100 %
 
           


(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refinery.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refinery.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity.
 
(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 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.

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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 via trucks that utilize the truck rack at the refinery. 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. These five 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 on June 1, 2003.

                 
    Years Ended  
    December 31,  
    2004     2003  
Woods Cross Refinery
               
Sales of produced refined products:
               
Gasolines
    59 %     62 %
Diesel fuels
    31 %     26 %
Jet fuels
    1 %     3 %
Fuel oils
    7 %     7 %
LPG and other
    2 %     2 %
 
           
Total
    100 %     100 %
 
           

For the 2005 year, our capital budget for the Woods Cross Refinery totals $40.8 million for various refining improvement projects, including the ULSD project approved in late 2004.

Our clean fuels strategy for the Woods Cross Refinery calls for the construction of a diesel hydrotreater unit, at an estimated cost of $33.6 million and execution of a long term hydrogen contract that will allow Holly Refining & Marketing — Woods Cross to produce ULSD by June 2006. This project will also create the infrastructure to allow for the potential of another project which would permit us to increase the percentage of sour crude oil runs through the refinery, although this project has not yet been scheduled or approved. The Woods Cross Refinery is also required to meet maximum achievable control technology (“MACT”) requirements on its fluid catalytic cracking (“FCC”) flue gas by January 1, 2010 and we plan to add equipment to the new diesel hydrotreater 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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Montana Refinery

Our petroleum refinery in Great Falls, Montana processes primarily sour Canadian crude oils and primarily serves markets in Montana. Beginning January 1, 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 about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation, depletion and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts under Generally Accepted Accounting Principles” following Item 7A under Part II of this Form 10-K.

                                         
                    Five Months     Fiscal Year     Five Months  
    Years Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
Montana Refinery
                                       
Crude Charge (BPD) (1)
    7,550       6,740       6,760       6,560       6,550  
Refinery production (BPD) (2)
    8,010       7,350       7,130       6,970       6,980  
Sales of produced refined products (BPD)
    7,970       7,150       7,080       7,230       7,760  
Sales of refined products (BPD) (3)
    8,190       7,620       7,890       7,540       8,060  
Refinery utilization (4)
    94.4 %     96.3 %     96.6 %     93.7 %     93.6 %
Average per produced barrel (5)
                                       
Net sales
  $ 43.10     $ 35.80     $ 32.18     $ 30.38     $ 31.44  
Cost of products
    35.37       28.17       26.01       22.23       22.36  
 
                             
Refinery gross margin
    7.73       7.63       6.17       8.15       9.08  
Refinery operating expenses (6)
    5.64       5.85       5.51       5.55       5.23  
 
                             
Net operating margin
  $ 2.09     $ 1.78     $ 0.66     $ 2.60     $ 3.85  
 
                             
Feedstocks:
                                       
Sour crude oil
    92 %     92 %     93 %     91 %     91 %
Other feedstocks and blends
    8 %     8 %     7 %     9 %     9 %
 
                             
Total
    100 %     100 %     100 %     100 %     100 %
 
                             


(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refinery.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refinery.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity.
 
(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.

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, 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.

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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 commenced in 2004.

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

                                         
                    Five Months     Fiscal Year        
    Years Ended     Ended     Ended     Five Months Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
Montana Refinery
                                       
Sales of produced refined products:
                                       
Gasolines
    41 %     40 %     42 %     40 %     35 %
Diesel fuels
    17 %     15 %     17 %     16 %     16 %
Jet fuels
    5 %     7 %     6 %     7 %     5 %
Asphalt
    33 %     33 %     31 %     33 %     40 %
LPG and other
    4 %     5 %     4 %     4 %     4 %
 
                             
Total
    100 %     100 %     100 %     100 %     100 %
 
                             

For the 2005 year, the capital budget for the Montana Refinery totals $2.1 million, most of which is for various refinery improvements. The Montana Refinery is capable, with a minimal additional investment, of producing LSG as required by January 2008 and we are studying changes necessary to comply with ULSD requirements by June 2010.

HOLLY ENERGY PARTNERS, L.P.

On March 15, 2004, we filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of limited partnership interests in HEP. 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. 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 unit over-allotment option that was exercised by the underwriters. Proceeds to HEP from the sale of the units were $145.5 million, net of underwriting commissions. Prior to the Alon transaction discussed below, we owned a 51% interest in HEP, including the general partner interest. The initial public offering represented the sale by us of a 49% interest in HEP. We consolidate the results of HEP and show the interest we do not own as a minority interest in ownership and earnings. HEP’s common units trade on the New York Stock Exchange under the symbol “HEP.” See “Liquidity and Capital Resources — Initial Public Offering of Holly Energy Partners” under Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information and for information about changes that have occurred due to the initial public offering for HEP.

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 and 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. The agreement provides that we transport or terminal volumes on certain of HEP’s initial facilities that results in revenues to HEP that will equal or exceed a specified minimum revenue amount annually (which will initially be $35.4 million and will adjust upward based on the producer price index) over the term of the agreement. HEP’s assets, not including the Alon assets acquired as discussed below, include:

  •   Refined Product Pipelines:

  •   approximately 780 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel, and jet fuel from the Navajo Refinery in New Mexico to our customers in

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      the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico; and
 
  •   a 70% interest in Rio Grande, a joint venture that owns a 249-mile refined product pipeline that transports liquid petroleum gases, or LPG’s, from West Texas to the Texas/Mexico border near El Paso for further transport into northern Mexico.

  •   Refined Product Terminals:

  •   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;
 
  •   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 514,000 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; 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 at our Woods Cross Refinery near Salt Lake City, Utah that is permitted to load over 25,000 BPD of light refined products.

HEP’s pipelines transport light refined products (gasoline, diesel and jet fuel) from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah, Idaho, Washington and northern Mexico. HEP also transports gasoline and diesel fuel for Alon from Orla, Texas to El Paso, Texas under a lease agreement providing for three long-term capacity lease arrangements. The substantial majority of HEP’s business is devoted to providing transportation and terminalling services to us.

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 for $120.0 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. As a result of the closing of this transaction, we now own 47.9% of HEP, including the 2% general partner interest, and other investors in HEP own 52.1%. 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.

In connection with the Alon transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon. Under this agreement, Alon will agree to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to HEP of $20.2 million per year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipeline and terminals taking into account a 5,000 BPSD expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. HEP granted Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have a right of first refusal to purchase the pipelines and terminals if HEP decides to sell them in the future. Additionally, HEP entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals to be acquired from Alon, where Alon will indemnify HEP subject to a $100,000 deductible and a $20 million maximum liability cap. The new HEP assets acquired from Alon include:

  •   a 105-mile light product pipeline from Alon’s refinery in Big Spring, Texas to a product terminal in Abilene, Texas;
 
  •   a 227-mile pipeline from Big Spring, Texas to a product terminal in Wichita Falls, Texas;
 
  •   a 47-mile pipeline from Wichita Falls, Texas to a product terminal in Duncan, Oklahoma;
 
  •   a 135-mile product pipeline from Midland, Texas to Orla, Texas where Alon connects into HEP’s southern pipeline system which transports light products to El Paso, Texas. Also acquired at Orla, Texas is a 135,000 barrel refined product tank farm; and

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  •   terminalling assets including a 127,000 barrel light product terminal in Abilene, Texas and a 220,000 barrel light product terminal in Wichita Falls, Texas.

HEP has budgeted maintenance capital expenditures of $1.5 million for 2005, excluding approximately $0.5 million of maintenance capital expenditures anticipated with respect to the assets acquired from Alon.

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 and terminalling agreements that were contributed to HEP, certain crude oil pipelines that were not contributed to HEP, and our interest in Rio Grande. 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 Pemex at a point near El Paso, Texas. Pemex 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. Prior to the 45% acquisition, we accounted for the earnings in the joint venture using the equity method. Effective with the purchase, we consolidated the results of Rio Grande with minority interest. 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 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 pursuant to a long-term lease of certain capacity of our 12-inch pipeline. In August 1998, FINA began transporting to El Paso 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, a subsidiary of an Israeli petroleum refining and marketing company, 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 exas 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 $65,000 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.

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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 2005.

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 will result in a book gain to us of $0.5 million.

Employees and Labor Relations
As of February 28, 2005, we had approximately 845 employees, of which approximately 319 are covered by collective bargaining agreements that will expire during 2006. We consider our employee relations to be good.

Regulation
Refinery and pipeline operations are subject to federal, state and local laws regulating the discharge of matter into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.

Our operations and many of the products we manufacture are subject to certain specific requirements of the Federal Clean Air Act (“CAA”) and related state and local regulations. The CAA contains provisions that 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 a Consent Agreement (“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 $9.5 million has been expended to date.

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 parts-per-million (“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.

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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. We have formulated our compliance plans for each of our three refineries. 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 it for the on-road diesel (June 1, 2006 for the Navajo and Woods Cross refineries, and June 1, 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.

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 federal Clean Air Act, 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. That oxygen requirement may be satisfied by adding to gasoline any one of many oxygen-containing materials including, among others, MTBE and ethanol. Ethanol is an oxygen containing compound that is manufactured primarily from “renewable” agricultural products and that has not been shown to exhibit the environmental concerns associated with MTBE. Ethanol serves as an oxygenate, an octane booster and as an extender of gasoline. 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 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 ordinary 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.

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

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environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at the New Mexico and Montana refineries and at pipeline transportation facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.

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

We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or more vigorous enforcement policies of regulatory 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 3. Legal Proceedings

On August 20, 2003, Frontier Oil Corporation filed a lawsuit in the Delaware Court of Chancery against us seeking declaratory relief and unspecified damages based on allegations that we repudiated our obligations and breached an implied covenant of good faith and fair dealing under a merger agreement announced in late March 2003 under which we and Frontier would be combined. On August 21, 2003, we formally notified Frontier of our position that pending and threatened toxic tort litigation with respect to oil properties operated by a subsidiary of Frontier from 1985 to 1995 adjacent to the campus of Beverly Hills High School constituted a breach of Frontier’s representations and warranties in the merger agreement as to the absence of litigation or other circumstances which could reasonably be expected to have a material adverse effect on Frontier. On September 2, 2003, we filed in the Delaware Court of Chancery our Answer and Counterclaims seeking declaratory judgments that we had not repudiated the merger agreement, that Frontier had repudiated the merger agreement, that Frontier had breached certain representations made by Frontier in the merger agreement, that our obligations under the merger agreement were and are excused and that we may terminate the merger agreement without liability, and seeking unspecified damages as well as costs and attorneys’ fees. A two-week trial in the Delaware Court of Chancery with respect to Frontier’s Complaint and our Answer and Counterclaims was completed in early March 2004. In this litigation, the maximum amount of damages asserted by Frontier against us is approximately $161 million plus interest and the maximum amount of damages we are asserting against Frontier is approximately $148 million plus interest. Post-trial briefing was completed in late April 2004 and in early May 2004 the court heard oral argument. A decision is expected to be announced within several months from the date of this report. Although it is not possible at the date of this report to predict the outcome of this litigation, we believe that the claims made by Frontier in the litigation are wholly without merit and that our counterclaims are well founded.

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. In October 2003, the judge before whom the case is pending issued a ruling that denied the Government’s motion for partial summary judgment on all issues raised by the Government and granted our motion for partial summary judgment on most of the issues we raised. The ruling on the motions for summary judgment in our case does not constitute a final ruling on our claims, but instead the judge’s ruling is expected to be followed by substantial discovery proceedings and then a trial on factual issues. The trial judge in our case issued an order in March 2004 to stay proceedings in our case while interlocutory appeals to the United States Court of Appeals for the Federal Circuit are pending on rulings by two other United States Court of Federal Claims judges in cases relating to

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military fuel sales of two other refining companies. The rulings in these two lower court cases were favorable to the position of the refining company in one case and favorable to the position of the Government in the other case. The appeals court heard oral argument on these related cases in January 2005 and a decision by the appeals court is expected to be issued in the first half of 2005. The appeals court’s decision in the related cases could substantially affect our lawsuit. It is not possible at the date of this report to predict the outcome of further proceedings in our case or the impact on our case of any decisions by the appeals court in the related cases, nor is it possible to predict what amount, if any, will ultimately be payable to us with respect to our lawsuit.

In July 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion on petitions for review of rulings by the FERC in proceedings brought by us and other parties against SFPP. The appeals court ruled 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. The court denied rehearing and rehearing en banc in October 2004. In January 2005, SFPP filed a petition for writ of certiorari to the United States Supreme Court seeking a review of certain aspects of the appeals court’s July 2004 decision. 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. Rulings by the FERC that were the subject of proceedings in the appeals court resulted in reparations payments to us in 2003 totaling approximately $15.3 million relating principally to the period from 1993 through July 2000. Because of the remand of the proceedings to the FERC for further consideration of several issues and SFPP’s January 2005 petition to the United States Supreme Court for a writ of certiorari on certain aspects of the case, it is not yet possible to determine whether the amount of reparations actually due to us for the period at issue 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 following the July 2004 appeals court decision 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 final reparations amount will be determined only after the rulings by the FERC on the remanded issues, the disposition of SFPP’s currently pending petition to the United States Supreme Court for writ of certiorari, and any further court proceedings on the case, which could include further review by the appeals court and possibly future petitions by one or more of the parties seeking United States Supreme Court review of issues in the case.

In May 2004, we responded to a Request for Information from the EPA under Section 114 of the Clean Air Act that we had received in April 2004. The Request for Information related to certain batches of gasoline produced and shipped by our Navajo Refinery in 2000 through 2003 and followed informal communications with the EPA concerning our compliance with environmental regulations applicable to gasolines produced by the Navajo Refinery. One specific matter that was the subject of informal communications with the EPA in early 2004 but that was not the subject of the Request for Information was the inadvertent issuance by the Navajo Refinery for almost 12 months during 2001 and 2002 of delivery documents to exchange partners that failed to properly contain statements required by federal regulations that the product did not meet the requirements for reformulated gasoline. We believe that this omission did not result in the delivery of non-reformulated gasoline to geographic areas where federal regulations require the use of reformulated gasoline. We discovered and corrected this problem, which had been caused by a computer system problem at the Navajo Refinery’s Artesia, New Mexico loading rack, and self-reported the violation in our annual attestation statement made to the EPA in May 2002. At the date of this report, we have no indication whether or not the EPA will consider any of the matters that were the subject of informal communications with the EPA in early 2004, including the matters that are the subject of the April 2004 Request for Information, as matters for enforcement action. If such enforcement action were taken, we do not believe that it would result in a material adverse effect on our results of operations or financial condition.

In November 2004, the Montana Department of Environmental Quality (“MDEQ”) notified us that the MDEQ was initiating an enforcement action against Montana Refining Company and seeking administrative civil penalties totaling $140,000. This enforcement action relates to alleged air quality violations that resulted from a failure in October 2003 of a vapor combustion unit (“VCU”) at Montana Refining Company’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. Montana Refining Company has been in discussions with the MDEQ concerning this matter and expects to enter into an agreement to settle the matter based upon payment of

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most or all of the proposed $140,000 penalty amount. Following the October 2003 incident that resulted in this enforcement action, Montana Refining Company has taken additional steps to avoid future delays in repairs to the VCU and to prevent operation of the truck loading rack without the VCU.

We are a 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.

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 2004.

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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  
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  
 
                               
2003
                               
First Quarter
  $ 14.40     $ 9.95     $ 0.055       6,820,400  
Second Quarter
  $ 15.01     $ 13.53     $ 0.055       8,296,400  
Third Quarter
  $ 14.25     $ 12.10     $ 0.055       10,620,800  
Fourth Quarter
  $ 13.85     $ 12.09     $ 0.055       4,297,200  

As of February 16, 2005, we had approximately 1,400 stockholders of record.

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 Senior Notes and Credit Agreement limit the payment of dividends. See Note 12 to the Consolidated Financial Statements.

The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this item is incorporated by reference into “Item 12. Security Ownership of Certain Beneficial Owners and Management.” of this annual report on Form 10-K from our definitive proxy statement for the annual meeting of stockholders to be held on May 9, 2005.

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Item 6. Selected Financial Data

The following table shows our selected financial information as of the dates or for the periods indicated. This table should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Form 10-K.

                                                         
                    Five Months     Fiscal Year     Five Months        
    Years Ended     Ended     Ended     Ended     Fiscal Years Ended  
    December 31,     December 31,     July 31,     December 31,     July 31,  
    2004     2003     2002     2002     2001     2001     2000  
    (In thousands, except per share data)  
FINANCIAL DATA
                                                       
For the period
                                                       
Sales and other revenues
  $ 2,246,373     $ 1,403,244     $ 448,637     $ 888,906     $ 363,854     $ 1,142,130     $ 965,946  
Income before income taxes
  $ 138,469     $ 74,359     $ 8,517     $ 50,896     $ 30,429     $ 121,895     $ 18,634  
Income tax provision
    54,590       28,306       3,114       18,867       11,822       48,445       7,189  
 
                                         
Net income
  $ 83,879     $ 46,053     $ 5,403     $ 32,029     $ 18,607     $ 73,450     $ 11,445  
 
                                         
 
                                                       
Net income per common share – basic
  $ 2.67     $ 1.49     $ 0.17     $ 1.03     $ 0.60     $ 2.42     $ 0.35  
 
                                                       
Net income per common share – diluted
  $ 2.61     $ 1.44     $ 0.17     $ 1.00     $ 0.58     $ 2.39     $ 0.35  
 
                                                       
Cash dividends declared per common share
  $ 0.29     $ 0.22     $ 0.055     $ 0.205     $ 0.05     $ 0.185     $ 0.17  
 
                                                       
Average number of common shares outstanding:
                                                       
Basic
    31,390       31,010       31,032       31,120       31,048       30,374       32,262  
Diluted
    32,170       32,032       31,804       31,942       31,898       30,774       32,262  
 
                                                       
Net cash provided by (used for) operating activities
  $ 165,763     $ 70,756     $ (8,733 )   $ 42,301     $ 5,935     $ 106,770     $ 46,804  
Net cash used for investing activities
  $ (47,619 )   $ (117,796 )   $ (24,769 )   $ (21,953 )   $ (4,755 )   $ (28,752 )   $ (20,143 )
Net cash provided by (used for) financing activities
  $ (62,374 )   $ 34,464     $ (13,862 )   $ (14,558 )   $ (10,387 )   $ (15,806 )   $ (27,227 )
 
                                                       
At end of period
                                                       
Cash, cash equivalents and investments in marketable securities
  $ 219,265     $ 11,690     $ 24,266     $ 71,630     $ 56,633     $ 65,840     $ 3,628  
Working capital
  $ 148,642     $ (27,140 )   $ 12,445     $ 59,873     $ 52,168     $ 57,731     $ 363  
Total assets
  $ 982,713     $ 706,558     $ 515,793     $ 502,306     $ 464,273     $ 490,429     $ 464,362  
Total debt, including current maturities and borrowings under the credit agreement
  $ 33,572     $ 67,142     $ 25,714     $ 34,285     $ 37,315     $ 42,857     $ 56,595  
Stockholders’ equity
  $ 339,916     $ 286,609     $ 228,494     $ 228,556     $ 217,961     $ 201,734     $ 129,581  

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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, 2004, we also owed a 51% interest in Holly Energy Partners, L.P. (“HEP”) which owns and operates pipeline and terminalling assets and owns a 70% interest in the Rio Grande Pipeline Company.

On March 15, 2004, we filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of limited partnership interests in HEP. 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. 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. Proceeds to HEP from the sale of the units were $145.5 million, net of underwriting commissions. After the initial public offering, we owned a 51% interest in HEP, including the general partner interest (our current ownership interest is 47.9% due to the issuance of additional units in the asset acquisition from Alon USA, Inc. as discussed below). The initial public offering represented the sale by us of a 49% interest in HEP. HEP’s common units trade on the New York Stock Exchange under the symbol “HEP.” See “–Liquidity and Capital Resources – Initial Public Offering of HEP” below for additional information and for information about changes that have occurred due to the initial public offering for HEP.

On February 28, 2005, HEP acquired from Alon USA, Inc. and certain of its affiliates (collectively “Alon”) over 500 miles of light products pipelines and two light product terminals for $120 million in cash and 937,500 HEP Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units in five years. As a result of the closing of this transaction, we now own 47.9% of HEP including the 2% general partner interest and other investors in HEP own 52.1%. HEP will continue to be included in our consolidated financial statements because of the control relationship between Holly Corporation and HEP. In connection with the transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon. HEP financed the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015. Although the senior notes will be reflected on our balance sheet (because HEP is a consolidated subsidiary) for dates when the senior notes are outstanding, Holly Corporation and its operating subsidiaries, other than HEP and its subsidiaries and controlling partners, are not liable on the senior notes either directly or as guarantors. The proceeds of the offering funded the $120 million cash portion of the consideration for the Alon transaction, and the balance was used to repay $30 million of outstanding indebtedness under HEP’s revolving credit agreement.

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 western United States. Our sales and other revenues for the year ended December 31, 2004 were $2,246.4 million and our net income for the year ended December 31, 2004 was $83.9 million. Our sales and other revenues and net income for the year ended December 31, 2004 increased from $1,403.2 million and $46.1 million, respectively, for the year ended December 31, 2003. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the year ended December 31, 2004 were $2,100.9 million, an increase from $1,359.0 million for the year ended December 31, 2003. For the year ended December 31, 2003, we realized a $16.2 million gain on the sale of our 400 mile Iatan crude oil gathering system located in West Texas to Plains All-American Pipeline, L.P. (“Plains”) and $15.2 million in reparations payments received.

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.

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On July 1, 2004, we received $27.2 million from Longhorn Partners which represents a principal payment of $25.0 million plus $2.2 million in interest on a note that became payable when the Longhorn Pipeline did not begin operations by July 1, 2004. This payment also resulted in the termination of our prepaid transportation rights on the Longhorn Pipeline.

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 the facility to $225 million subject to certain conditions. The new credit facility replaced our prior revolving credit facility with the Canadian Imperial Bank of Commerce and may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes.

We are involved in litigation with Frontier Oil Corporation relating to our agreement to merge entered into on March 30, 2003. The trial with respect to Frontier’s amended Complaint and our Answer and Counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. In this litigation, the maximum amount of damages currently asserted by Frontier against us is approximately $161 million plus interest and the maximum amount of damages currently asserted by us against Frontier is approximately $148 million plus interest. A decision is expected to be announced within several months.

As a result of a two-for-one stock split effective August 30, 2004, all references to the number of shares of common stock (other than authorized shares and other than issued shares and treasury shares at December 31, 2003 shown on our Consolidated Balance Sheet) and per share amounts have been adjusted to reflect the split on a retroactive basis. In August 2004, we resumed repurchases of our stock under our $20.0 million stock repurchase program that we originally announced in October 2001, and we completed the $20.0 million repurchase program in September 2004.

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RESULTS OF OPERATIONS

Financial Data

Information at December 31, 2004 and 2003 and for the years ended December 31, 2004 and 2003 and July 31, 2002 and 2001 and the five months ended December 31, 2002 is derived from our audited financial statements. Information for the five months ended December 31, 2001 is derived from our accounting records.

                                                 
    Years Ended     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
    (In thousands, except per share data)  
Sales and other revenues
  $ 2,246,373     $ 1,403,244     $ 888,906     $ 1,142,130     $ 448,637     $ 363,854  
Operating costs and expenses:
                                               
Cost of products sold (exclusive of depreciation, depletion, and amortization)
    1,835,997       1,155,858       698,245       871,321       377,538       278,837  
Operating expenses (exclusive of depreciation, depletion, and amortization)
    168,264       131,045       96,289       100,410       41,566       40,337  
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization)
    55,428       34,782       22,248       23,123       9,025       8,963  
Depreciation, depletion and amortization
    40,481       36,275       27,699       27,327       11,726       10,875  
Exploration expenses, including dry holes
    689       1,031       1,379       2,042       392       456  
 
                                   
Total operating costs and expenses
    2,100,859       1,358,991       845,860       1,024,223       440,247       339,468  
 
                                   
 
                                               
Gain on sale of assets
          15,814                          
 
                                   
 
                                               
Income from operations
    145,514       60,067       43,046       117,907       8,390       24,386  
Other income (expense)
                                               
Equity in earnings of joint ventures
    (318 )     1,398       7,753       5,302       726       5,037  
Minority interest in income of partnerships
    (7,575 )     (758 )                        
Interest income (expense), net
    848       (1,678 )     (1,425 )     (2,467 )     (599 )     (516 )
Reparations payment received
          15,330                          
Other Income
                1,522       1,153             1,522  
 
                                   
 
    (7,045 )     14,292       7,850       3,988       127       6,043  
 
                                   
Income before income taxes
    138,469       74,359       50,896       121,895       8,517       30,429  
Income tax provision
    54,590       28,306       18,867       48,445       3,114       11,822  
 
                                   
Net income
  $ 83,879     $ 46,053     $ 32,029     $ 73,450     $ 5,403     $ 18,607  
 
                                   
 
                                               
Net income per common share – basic
  $ 2.67     $ 1.49     $ 1.03     $ 2.42     $ 0.17     $ 0.60  
 
                                               
Net income per common share – diluted
  $ 2.61     $ 1.44     $ 1.00     $ 2.39     $ 0.17     $ 0.58  
 
                                               
Cash dividends declared per common share
  $ 0.29     $ 0.22     $ 0.205     $ 0.185     $ 0.055     $ 0.05  

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Balance Sheet Data

                 
    Years Ended December 31,  
    2004     2003  
    (Dollars in thousands)  
Cash, cash equivalents and investments in marketable securities
  $ 219,265     $ 11,690  
Working capital
  $ 148,642     $ (27,140 )
Total assets
  $ 982,713     $ 706,558  
Total debt, including current maturities and bank borrowings (1)
  $ 33,572     $ 67,142  
Minority interest
  $ 157,550     $ 14,475  
Stockholders’ equity
  $ 339,916     $ 268,609  
Total debt to capitalization ratio (2)
    9.0 %     20.0 %


(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     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
    (In thousands)
Net cash provided by (used for) operating activities
  $ 165,763     $ 70,756     $ 42,301     $ 106,770     $ (8,733 )   $ 5,935  
Net cash used for investing activities
  $ (47,619 )   $ (117,796 )   $ (21,953 )   $ (28,752 )   $ (24,769 )   $ (4,755 )
Net cash provided by (used for) financing activities
  $ (62,374 )   $ 34,464     $ (14,558 )   $ (15,806 )   $ (13,862 )   $ (10,387 )
Capital expenditures
  $ 37,780     $ 74,642     $ 35,313     $ 28,571     $ 22,793     $ 10,405  
EBITDA (1)
  $ 178,102     $ 112,312     $ 80,020     $ 151,689     $ 20,842     $ 41,820  


(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.

As of July 13, 2004, the closing of the initial public offering of HEP, we changed our segments to reflect our new business divisions. Our two new major business segments are: Refining and HEP. The new Refining segment will not be the same as the old Refining segment since some of those assets were contributed to HEP. Likewise, HEP will not be the same as the old Pipeline Transportation segment. Since it is impracticable to restate prior periods for our new business segments, we are including the old business segments for all periods presented as well as the new business segments from July 13, 2004 forward.

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    Year Ended  
    December 31,  
    2004  
    (In thousands)  
Business segments after July 13, 2004 (reporting January 1, 2004 through December 31, 2004 amounts):
 
       
Sales and other revenues (1)
       
Refining
  $ 2,234,697  
HEP
    28,182  
Corporate and Other
    1,916  
Consolidations and Eliminations
    (18,422 )
 
     
Consolidated
  $ 2,246,373  
 
     
 
       
Income (loss) from operations (1)
       
Refining
  $ 175,133  
HEP
    12,980  
Corporate and Other
    (42,599 )
 
     
Consolidated
  $ 145,514  
 
     
                                                 
                    Fiscal Year        
    Years Ended     Ended     Five Months Ended  
    December 31,     July, 31     December 31,  
    2004     2003     2002     2001     2002     2001  
    (In thousands)  
Business segments prior to July 13, 2004 (reporting January 1, 2004 through December 31, 2004):
 
                                               
Sales and other revenues (2)
                                               
Refining
  $ 2,220,985     $ 1,373,406     $ 868,730     $ 1,120,248     $ 439,788     $ 355,408  
Pipeline Transportation
    23,977       21,030       18,588       18,454       8,245       7,623  
Corporate and Other
    1,411       8,808       1,588       3,428       604       823  
 
                                   
Consolidated
  $ 2,246,373     $ 1,403,244     $ 888,906     $ 1,142,130     $ 448,637     $ 363,854  
 
                                   
 
                                               
Income (loss) from operations (2)
                                               
Refining
    172,144     $ 53,854     $ 42,725     $ 116,218     $ 8,017     $ 23,887  
Pipeline Transportation
    15,969       29,110       10,621       10,243       4,800       4,128  
Corporate and Other
    (42,599 )     (22,897 )     (10,300 )     (8,554 )     (4,427 )     (3,629 )
 
                                   
Consolidated
  $ 145,514     $ 60,067     $ 43,046     $ 117,907     $ 8,390     $ 24,386  
 
                                   


(1)   As of July 13, 2004, the new 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. Included in the new Refining segment are costs relating to certain crude oil and intermediate product pipelines that we still own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The new Refining segment also includes the purchasing of crude oil and wholesale and branded marketing of refined products, along with our equity in earnings from our then 49% interest in NK Asphalt Partners, which manufactures and markets asphalt and asphalt products in Arizona and New Mexico. The cost of pipeline transportation and terminal services provided by HEP is included in the new Refining segment. The HEP segment includes approximately 780 miles of our pipeline assets in Texas and New Mexico. Revenues from 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 the earnings from our indirect interest in the Rio Grande Pipeline Company (“Rio Grande”) which provides petroleum products transportation. Results of operations involving the assets included in the new HEP segment prior to July 13, 2004 are included in the new Refining segment for reporting purposes. The elimination column includes the elimination of the revenue and costs associated with our pipeline transportation services between us and HEP as well as the elimination of minority interest in income of HEP.
 
(2)   Prior to July 13, 2004, the old 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. Included in the old Refining segment are costs relating to pipelines and terminals that operate in conjunction with the old Refining segment as part of

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    the supply and distribution networks of the refineries. The old Refining segment also includes our equity in earnings from our then 49% interest in NK Asphalt Partners and the minority interest in income of HEP. The old Pipeline Transportation segment included approximately 500 miles of our pipeline assets in Texas and New Mexico and our 70% interest in Rio Grande. Revenues of the old Pipeline Transportation segment were earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations.

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     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003 (8)     2002     2001     2002     2001  
Consolidated
                                               
Crude Charge (BPD) (1)
    102,230       76,040       60,200       64,020       64,270       54,480  
Refinery production (BPD) (2)
    111,070       85,030       66,360       69,640       72,280       59,740  
Sales of produced refined products (BPD)
    110,370       82,900       67,060       69,080       70,490       60,580  
Sales of refined products (BPD) (3)
    118,760       95,420       76,420       77,000       82,260       73,310  
Refinery utilization (4)
    94.7 %     93.2 %     89.9 %     95.6 %     95.9 %     81.3 %
 
                                               
Average per produced barrel (5)
                                               
Net sales
  $ 50.80     $ 38.99     $ 30.95     $ 39.60     $ 34.65     $ 31.71  
Cost of products (6)
    41.70       31.76       24.22       29.80       29.10       23.72  
 
                                   
Refinery gross margin
    9.10       7.23       6.73       9.80       5.55       7.99  
Refinery operating expenses (7)
    3.53       3.58       3.13       3.19       3.09       3.47  
 
                                   
Net operating margin
  $ 5.57     $ 3.65     $ 3.60     $ 6.61     $ 2.46     $ 4.52  
 
                                   


(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity.
 
(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 since the purchase date.

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 is 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

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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.

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. Liquidations of certain LIFO inventory quantities that were carried at lower costs compared to current costs contributed $4.9 million to gross refining margin in 2004. 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 $131.0 million in 2003 to $168.3 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.

Selling, General and Administrative Expenses
Selling, general and administrative expenses increased 59% from $34.8 million in 2003 to $55.4 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.

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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 is 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 represents $25.0 principal plus $2.2 million in interest on the Longhorn Partners note and results 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.

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 Kinder Morgan’s SFPP, L.P. (“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 relates both to taxes on income before income taxes and 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.

Results of Operations – Fiscal Year Ended July 31, 2002 Compared to Fiscal July 31, 2001

Summary
For the fiscal year ended July 31, 2002, net income was $32.0 million ($1.00 per diluted share) compared to $73.5 million ($2.39 per diluted share) for the fiscal year ended July 31, 2001. During the fiscal year ended July 31, 2002, we and the refinery industry as a whole experienced substantially lower refining margins than prevailed in the prior fiscal year.

Sales and Other Revenues
Sales and other revenues decreased 22% from $1,142.1 million in fiscal 2001 to $888.9 million in fiscal 2002. The average sales prices per produced barrel sold decreased 22% from $39.60 in fiscal 2001 to $30.95 in fiscal 2002, due primarily to lower refined product sales prices. The total volume of refined products we sold was substantially the same in fiscal 2002 as compared to fiscal 2001.

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Cost of Products Sold
Cost of products sold decreased 20% from $871.3 million in fiscal 2001 to $698.2 million in fiscal 2002 due primarily to lower costs of purchased crude oil. The average price paid per barrel of crude oil decreased 19% from $29.80 in fiscal 2001 to $24.22 in fiscal 2002.

Gross Refinery Margins
The gross refinery margin per barrel was $6.73 in fiscal 2002 as compared to $9.80 for fiscal 2001. Gross refinery margins do not include the effect of depreciation, depletion and amortization. Liquidations of certain LIFO inventory quantities that were carried at lower costs compared to current costs contributed $2.3 million to gross refining margin in fiscal 2002. 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 decreased 4% from $100.4 million in fiscal 2001 to $96.3 million in fiscal 2002 due primarily to lower utility costs.

Selling, General and Administrative Expenses
Selling, general and administrative expenses decreased 4% from $23.1 million in fiscal 2001 to $22.2 million in fiscal 2002 primarily due to decreased legal and compensation expenses.

Equity in Earnings of Joint Ventures
Equity in earnings of joint ventures increased 46% from $5.3 million is fiscal 2001 to $7.8 million in fiscal 2002 due primarily to record performance at the NK Asphalt joint venture. Equity in earnings of joint ventures included $6.3 million and $4.2 million from our 49% interest in the NK Asphalt joint venture and $1.5 million and $1.1 million from our 25% interest in the Rio Grande joint venture for fiscal years ended July 31, 2002 and 2001, respectively.

Interest Expense and Interest Income
Interest expense declined $2.0 million during fiscal 2002 from fiscal 2001 primarily due to reduced interest costs as we made required principal payments on long-term debt. The reduction in interest expense was partially offset by a $1.0 million decrease in interest income for fiscal 2002, as compared to fiscal 2001, due primarily to lower interest rates on invested funds.

Income Taxes
Income taxes decreased by 61% from $48.4 million in fiscal 2001 to $18.9 million in fiscal 2002 due primarily to a $71.0 million reduction in net income before taxes, and to a lesser extent, a decrease in the effective tax rate from 39.7% to 37.1%. The effective tax rate decreased due to state tax planning strategies implemented and net operating loss benefits recognized.

Results of Operations – Five Months Ended December 31, 2002 Compared to Five Months Ended December 31, 2001

Summary
For the five months ended December 31, 2002, net income was $5.4 million ($0.17 per diluted share) compared to $18.6 million ($0.58 per diluted share) for the five months ended December 31, 2001. The decrease in net income for the five months ended December 31, 2002, as compared to the five months ended December 31, 2001, was principally the result of lower refined product margins. During the five months ended December 31, 2001, we and the refining industry as a whole were still experiencing very favorable refined product margins. Equity in earnings at our asphalt joint venture declined substantially for the five months ended December 31, 2002 compared to the five months ended December 31, 2001. Sales volumes increased for the five months ended December 31, 2002 compared to the five months ended December 31, 2001 when sales volumes were lower due to planned maintenance turnarounds.

Sales and Other Revenues
Sales and other revenues increased 23% from $363.9 million for the five months ended December 31, 2001 to

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$448.6 million for the five months ended December 31, 2002 due principally to higher refined product sales prices. The average sales price we received per produced barrel sold increased 9% from $31.71 for the five months ended December 31, 2001 to $34.65 for the five months ended December 31, 2002. The total volume of refined products we sold increased 12% in the five months ended December 31, 2002 as compared to the five months ended December 31, 2001 when we were performing planned maintenance turnarounds.

Cost of Products Sold
Cost of products sold increased 35% from $278.8 million for the five months ended December 31, 2001 to $377.5 million for the five months ended December 31, 2002. The $98.7 million increase was primarily due to higher costs of crude oil and, to a lesser extent, higher production volumes. The average price we paid per barrel of crude oil purchased increased 23% from $23.72 for the five months ended December 31, 2001 to $29.10 for the five months ended December 31, 2002.

Gross Refinery Margins
The gross refining margin per produced barrel decreased 31% from $7.99 for the five months ended December 31, 2001 to $5.55 for the five months ended December 31, 2002. The decrease from 2001 to 2002 was due primarily to the increases in raw material costs that were at a greater rate than increases in sales prices. Gross refinery margin does not include the effect of depreciation, depletion and 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 3% from $40.3 million for the five months ended December 31, 2001 to $41.6 million for the five months ended December 31, 2002 primarily due to higher natural gas prices and higher maintenance expenses.

Equity in Earnings of Joint Ventures
Equity in earnings of joint ventures declined 86% from $5.0 million for the five months ended December 31, 2001 to $0.7 million for the five months ended December 31, 2002. The $4.3 million decline resulted primarily from lower earnings at our NK Asphalt joint venture for the five months ended December 31, 2002 compared to substantial earnings for the joint venture in the five months ended December 31, 2001 and an inventory charge of $1.3 million for the five months ended December 31, 2002.

Income Taxes
Income taxes decreased 74% from $11.8 million for the five months ended December 31, 2001 to $3.1 million for the five months ended December 31, 2002 due to a $21.9 million decrease in net income before taxes. The effective tax rate for the five months ended December 31, 2001 was 38.9% as compared to 36.6% for the five months ended December 31, 2002.

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. As of December 31, 2004, we had cash and cash equivalents of $67.4

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million (including $19.1 million held by HEP), marketable securities with maturities under one year of $96.2 million and marketable securities with maturities greater than one year, but less than two years, of $55.6 million.

Cash and cash equivalents increased by $119.8 million during the year ended December 31, 2004. The cash flow generated from operations of $165.8 million along with the cash provided by investing activities of $15.8 million greatly exceeded the cash used for financing activities of $61.7 million. Working capital increased during the year ended December 31, 2004 by $175.8 million.

On July 1, 2004, we entered into a new $175 million secured revolving credit facility which replaced our prior revolving credit facility with Canadian Imperial Bank of Commerce. The new credit facility with Bank of America, as administrative agent and a lender, has a term of four years and we may increase it to $225 million subject to certain conditions. The new credit facility may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes. As of December 31, 2004, we had letters of credit outstanding under our revolving credit facility of $1.2 million and had no borrowings outstanding. Additionally, a new credit facility was entered into for the benefit of HEP, as described below.

On October 30, 2001, we announced plans to repurchase up to $20.0 million of our common stock. On August 2, 2004, we announced that we would resume our plans to repurchase shares of our common stock under the $20.0 million repurchase program and completed our repurchases in September 2004. The repurchases were made from time to time in open market purchases or privately negotiated transactions, subject to price and availability and were financed with available corporate funds. During the year ended December 31, 2004, we repurchased 766,300 shares at a cost of approximately $15.3 million. During the year ended December 31, 2003, we repurchased 86,000 shares at a cost of approximately $0.9 million. From inception of the plan through October 31, 2004, we repurchased 1,311,100 shares at a cost of approximately $20.0 million and completed the $20.0 million repurchase program.

We believe our current cash, cash equivalents, and marketable securities, including the proceeds from HEP transferred to us in its initial public offering, along with future internally generated cash flow, and funds available under our new credit facilities provide sufficient resources to fund planned capital projects, scheduled repayments of our senior notes, continued payment of dividends, distributions by HEP to minority interest partners of HEP (although dividend and distribution payments must be approved by the respective Board of Directors and cannot be guaranteed), and our liquidity needs for the foreseeable future.

Initial Public Offering of Holly Energy Partners

On March 15, 2004, we filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of limited partnership interests in HEP. 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.

On July 7, 2004, HEP priced 6,100,000 common units for the initial public offering and on July 8, 2004, HEP’s common units began trading on the New York Stock Exchange under the symbol “HEP.” 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 unit over-allotment option that was exercised by the underwriters. Proceeds to HEP from the sale of the units were $145.5 million, net of underwriting commissions. 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.

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. As of December 31, 2004, $25.0 million was drawn under the facility.

In July 2004, HEP repaid Holly Corporation for $30.1 million of debt and made a distribution to Holly Corporation of $125.6 million. Beginning with the third quarter of 2004, we consolidate the results of HEP with minority interest treatment for the common units.

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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 the other limited partners to receive such distributions.

In connection with the offering, 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 will initially be $35.4 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.

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. Upon the closing of this transaction, we now own 47.9% of HEP, including the 2% general partner interest, and other investors in HEP own 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 6.25% senior notes due 2015. 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. Under this agreement, Alon will agree to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to HEP of $20.2 million per year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipeline and terminals taking into account a 5,000 BPSD expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. HEP granted Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have a right of first refusal to purchase the pipelines and terminals if HEP decides to sell them in the future. Additionally, HEP entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals to be acquired from Alon, where Alon will indemnify HEP subject to a $100,000 deductible and a $20 million maximum liability cap.

Cash Flows — Operating Activities

Net cash provided by operating activities amounted to $165.8 million in 2004 compared to $70.8 million in 2003. Comparing 2004 to 2003, the $95.0 million increase in cash provided by operations was primarily the result of a $37.8 million increase in net income (excluding 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 $13.9 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, and a decrease in turnaround expenditures incurred of $17.6 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

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$61.9 million, an increase in prepayments and other in 2004 as compared to a decrease in 2003 resulting in a net increase of $4.9 million and a decrease of $45.7 million in deferred taxes.

Net cash provided by operating activities amounted to $42.3 million in fiscal 2002 compared to $106.8 million in fiscal 2001. Comparing fiscal 2002 to fiscal 2001, the $64.5 million decrease in cash provided by operations was primarily the result of a $41.4 million decrease in net income, a $9.1 million increase in expenditures on turnarounds and changes in working capital items.

Cash flows used for operating activities for the five months ended December 31, 2002 were $8.7 million. For the comparable five months ended December 31, 2001, cash provided by operating activities was $5.9 million. The $14.7 million decrease in cash used for operating activities for the five months ended December 31, 2002 as compared to the five months ended December 31, 2001 was due to a reduction in net income of $13.2 million and a payment of $25.0 million for prepaid transportation services, offset by reduced turnaround expenditures of $14.1 million as compared to the five months ended December 31, 2001 and changes in working capital items.

Cash Flows — Investing Activities and Capital Projects

Cash flows used for investing activities were $47.6 million for 2004 compared to $117.8 million for 2003. In July 2004, we received $145.5 million in net proceeds from the HEP offering. We expended $3.5 million in formation costs for HEP. 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 received a distribution of $4.4 million from our asphalt joint venture, 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. In accounting for the purchase of the Woods Cross Refinery, 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. Effective with the purchase of additional interest in the Rio Grande joint venture, we consolidate the results of the Rio Grande Pipeline Company and reflect a minority interest in ownership and earnings. 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. In addition to cash, at the acquisition date, the Rio Grande Pipeline Company 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. Additionally in 2003, we spent $3.3 million for investments in the asphalt joint venture. Our net cash flows used for investing activities was reduced in 2003 by a $4.9 million distribution from the asphalt joint venture, by $24.0 million in proceeds from the sale of the pipeline assets, and by $8.5 million in proceeds (including inventory sold) from the sale of retail assets purchased as part of the Woods Cross Refinery acquisition.

Cash flows used for investing activities were $22.0 million in fiscal 2002. Cash expenditures for property, plant and equipment were $35.3 million in fiscal 2002. We also spent $3.3 million for our investment in the asphalt joint venture, offset by a $3.2 million distribution to us from the Rio Grande joint venture, an $8.5 million distribution to us from the asphalt joint venture, $0.5 million in proceeds from the sale of a 1% interest in the asphalt joint venture and $4.5 million in proceeds from the sale of marketable equity securities.

Cash flows used for investing activities were $28.8 million in fiscal 2001. Cash expenditures for property, plant and equipment were $28.6 million in fiscal 2001. We also spent $5.9 million for our investment in the asphalt joint venture which was offset by a $5.6 million distribution to us from the asphalt joint venture and a $0.1 million distribution from the Rio Grande joint venture.

Cash flows used for investing activities were $24.8 million for the five months ended December 31, 2002. Cash expenditures for property, plant and equipment were $22.8 million for the five months ended December 31, 2002. During that time period, we also spent $2.5 million as an initial deposit for the acquisition of the Woods Cross refinery and retail stations and received a $0.5 million distribution from the Rio Grande joint venture.

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Cash flows used for investing activities were $4.8 million for the five months ended December 31, 2001. Cash expenditures for property, plant and equipment were $10.4 million for the five months ended December 31, 2001. During that time period, we also received a $1.1 million distribution from the Rio Grande joint venture and received $4.5 million in proceeds from the sale of marketable equity securities.

In recent years, we have invested significant amounts in capital expenditures to expand and enhance the Navajo Refinery and expand its 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. The total cost of the project was $85.0 million, excluding capitalized interest. The 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 have been adopted in the Phoenix market for winter months beginning in late 2000, and enables us to meet the recently adopted EPA nationwide low-sulfur gasoline requirements that became effective January 1, 2004. 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.

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 capital budget for 2005 is approximately $117.6 million, including $73.8 million approved late in 2004 for ultra low sulfur diesel (“ULSD”) projects at the Woods Cross and Navajo refineries and a ROSE asphalt project at the Navajo Refinery, all described below. The capital budget is comprised of $60.3 million for refining improvement projects for the Navajo Refinery, $40.8 million for projects at the Woods Cross Refinery, $2.1 million for projects at the Montana Refinery, $8.4 million for transportation and marketing projects, $1.5 million for HEP projects (approved by HEP’s Board of Directors), and $4.5 million for information technology and other miscellaneous projects. For 2005 we expect to expend approximately $80.0 million on capital projects, which amount includes certain carryovers of capital projects from previous years, less carryovers to 2006 of certain of the currently approved capital projects.

Our combined 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 USLD service, the expansion of the continuous catalytic reformer and the conversion of the kerosene hydrotreater to naphtha service, which will allow us to produce ULSD by June 2006. Additionally, we plan to revamp our crude and vacuum units at Artesia and Lovington for improved energy conservation and cutpoints which will also permit the processing of up to 85,000 BPSD of crude. We estimate the total cost to complete the ULSD project and expansion of our crude oil refining capacity to 85,000 at $52 million and plan for completion in 2006. It is currently anticipated that these projects will also permit the Navajo Refinery without substantial additional investment to comply with low-sulfur gasoline (“LSG”) requirements that will become applicable in 2010.

We have purchased and plan to relocate and refurbish an existing 4,500 BPSD ROSE asphalt unit for the Navajo Refinery at a total estimated cost of $16.4 million. This project will upgrade asphalt to higher valued gasoline and diesel and is expected to be operational in the first quarter of 2006.

Our clean fuels strategy for the Woods Cross Refinery calls for the construction of a diesel hydrotreater unit, at an estimated cost of $33.6 million and execution of a long term hydrogen contract that will allow Holly Refining and Marketing – Woods Cross to produce ULSD by June 2006. This project will also create the infrastructure to allow for the potential of another 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 through the refinery. The Woods Cross Refinery is also required to meet maximum achievable control technology (“MACT”) requirements on its fluid catalytic cracking (“FCC”) flue gas by January 1, 2010 and we plan to add equipment to the new diesel hydrotreater to

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desulfurize FCC feed prior to this 2010 date to comply with these requirements, as well as the future LSG requirements.

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

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 $20.0 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

Cash flows used for financing activities were $62.4 million in 2004, as compared to cash flows provided by financing activities of $34.5 million in 2003. During 2004, we 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 new credit facility and HEP’s financing. In 2003, we borrowed $50.0 million under our credit agreement as partial funding for the Navajo Refinery hydrotreater and expansion project, the Woods Cross acquisition, and the purchase of an additional 45% interest in the Rio Grande joint venture. The credit agreement borrowings plus the $0.4 million received upon the exercise of stock options in 2003 were partially offset by an $8.6 million scheduled repayment of long-term debt, $0.9 million spent to repurchase shares of common stock and $5.1 million used to pay dividends.

Cash flows used for financing activities amounted to $14.6 million in fiscal 2002 and $15.8 million in fiscal 2001. During fiscal 2002, we repaid $8.6 million of our long-term fixed rate term debt, received proceeds of $2.0 million for common stock issued upon exercise of stock options, paid $1.6 million to repurchase shares of common stock and paid $6.4 million in dividends. During fiscal 2001, we repaid $13.7 million of our long-term fixed rate debt, received proceeds of $4.4 million for common stock issued upon exercise of stock options and paid $5.6 million in dividends. We had no bank borrowings during the 2002 fiscal year or the 2001 fiscal year.

Cash flows used for financing activities amounted to $13.9 million and $10.4 million for the five months ended December 31, 2002 and 2001, respectively. During the five months ended December 31, 2002, we repaid $8.6 million of our long-term fixed rate debt, purchased treasury stock for $2.2 million and paid $3.4 million in dividends. During the five months ended December 31, 2001, we repaid $8.6 million of our long-term fixed rate debt, received proceeds of $1.5 million from common stock issued upon exercise of stock options and paid $3.1 million in dividends.

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Contractual Obligations and Commitments

The following table presents our long-term contractual obligations as of December 31, 2004 in total and by period due beginning in 2005. These items include our long-term debt based on maturity dates and our operating lease commitments. Our operating leases contain renewal options that are not reflected in the table below which are likely to be exercised.

                                         
            Payments Due by Period  
            Less than                     Over  
Contractual Obligations   Total     1 Year     2-3 Years     4-5 Years     5 Years  
    (In thousands)  
Long-term debt (stated maturities)
  $ 33,572     $ 8,572     $     $ 25,000     $  
Operating leases
  $ 18,933     $ 6,268     $ 9,800     $ 1,574     $ 1,291  

In July 2000, we formed a joint venture with a subsidiary of Koch Materials Company (“Koch”) called NK Asphalt Partners, 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. In January 2002, we sold a 1% equity interest to Koch, thereby reducing our interest from 50% to 49%. All asphalt produced at the Navajo Refinery is sold at market prices to the joint venture under a supply agreement. We made a contribution to the joint venture during 2004 for $3.25 million and were required to make additional contributions to the joint venture of up to $3.25 million for each of the next six years contingent on the earnings level of the joint venture. In February 2005, we purchased the 51% interest owned by Koch Materials Company in NK Asphalt Partners for $16.9 million plus approximately $5 million for working capital. This purchase increased our ownership in NK Asphalt Partners from 49% to 100%, and eliminated any further obligations we have had with respect to the remaining $3.25 million annual payments.

In December 2001, we entered into a Consent Agreement (“Consent Agreement”) with the Environmental Protection Agency (“EPA”), the New Mexico Environment Department, and the Montana Department of Environmental Quality. 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 $9.5 million has been expended to date.

In connection with the HEP offering, discussed above, 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 revenue to HEP that will equal or exceed a specified minimum revenue amount annually (which will initially be $35.4 million and will adjust upward based on the producer price index) over the term of the agreement.

CRITICAL ACCOUNTING POLICIES

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

Inventory Valuation
Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the last-in, first-out (“LIFO”) inventory valuation methodology and market is determined using current estimated selling

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prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years such as 2004 when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2004, our LIFO inventory layers were valued at historical costs that were established in years when price levels were much lower; therefore, our results of operation are less sensitive to current market price reductions. As of December 31, 2004, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was approximately $78.7 million.

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

Long-lived Assets
We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2004 and 2003, the fiscal years ended July 31, 2002 and 2001 or the five months ended December 31, 2002 and 2001.

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. 132 (revised) “Employers’ Disclosures about Pensions and Other Postretirement Benefits”
In December 2003, the FASB issued SFAS 132 (revised), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This revision requires additional disclosures in annual reports concerning the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. Additionally, the standard now requires interim period disclosures regarding net periodic pension cost and employer contributions. The standard is effective for fiscal years ending after December 15, 2003. We adopted the standard on December 31, 2003.

SFAS No. 123 (revised) “Share-Based Payment”
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. This standard will be effective for us for the first interim period beginning after June 15, 2005. We do not believe the adoption of this

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standard will have a material effect on our financial condition, results of operations or cash flows.

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4”
In December 2004, the FASB issued FASB 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 will be effective for fiscal years beginning after June 15, 2005. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements.

ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS

Many factors outside of our control affect the prices and demand for our products, including general economic conditions and market factors, seasonal and weather-related factors and governmental regulations and policies.

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. 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 jet 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 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 is normally 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.

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. The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related 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.

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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, such as El Paso, Albuquerque and Phoenix.

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. In December 2003, the United States Court of Appeals for the Fifth Circuit affirmed a decision by the federal district court in Austin, Texas that allowed the Longhorn Pipeline to begin operations when agreed improvements had been completed. In October 2004, the Supreme Court of the United States denied review of the Court of Appeals decision. It is our understanding that there have been some limited shipments of refined products on the Longhorn Pipeline in recent months.

The Longhorn Pipeline could result in downward pressure on wholesale refined products margins in El Paso and related markets. 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 its common carrier pipeline from El Paso to Albuquerque to address its capacity constraint, SFPP has announced plans to expand the capacity of its pipeline from El Paso to the Arizona market by between 45,000 and 50,000 BPD. According to industry sources, this expansion is expected to be completed during the second quarter of 2006. Although our results of operations might be adversely impacted by the start-up of the Longhorn Pipeline and by the expansion of SFPP’s El Paso to Arizona pipeline, we are unable to predict at this time the extent to which it could be negatively affected.

In November 2002, as a result of our settlement of litigation with Longhorn Partners, we prepaid $25.0 million to Longhorn Partners for the shipment of 7,000 BPD of refined products from the Gulf Coast to El Paso in a period of up to six years from the date the Longhorn Pipeline begins operations if such operations began by July 1, 2004. Under the agreement, the prepayment would have covered shipments of 7,000 BPD for approximately four and a half years assuming there were no curtailments of service once operations began. On July 1, 2004, under the terms of the November 2002 settlement agreement that terminated litigation between us and Longhorn Partners, we received $25.0 million in principle plus $2.2 million of interest from Longhorn Partners. This repayment resulted in termination of our prepaid transportation rights under the November 2002 settlement agreement.

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 if the most direct route were used) have made transportation by truck unfeasible and have discouraged the substantial investment required for development of refined products pipelines from the Gulf Coast to El Paso.

In 1998, a Texaco, Inc. subsidiary converted an existing 16-inch crude oil products pipeline running 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, and can transport to El Paso approximately 18,000 to 20,000 BPD of refined products produced on the Texas Gulf Coast (this capacity replaced a similar volume that had been produced in the Shell refinery in Odessa, Texas, which was shut down in 1998). The Magellan pipeline from the Gulf Coast to Midland has the potential to be linked to existing or new pipelines running from the Midland, Texas area to El Paso with the result that substantial additional volumes of refined products could be transported from the Gulf Coast to El Paso.

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.

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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.

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 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 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 by between 45,000 and 50,000 BPD. According to industry sources, this expansion is expected to be completed during the second quarter of 2006. 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 the 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. In addition, we lease from Enterprise Products Partners, L.P. a pipeline running from near the Navajo Refinery to the Albuquerque vicinity and Bloomfield, New Mexico, (the “Leased Pipeline”). We operate 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. Transportation of petroleum products to markets in northwest New Mexico and diesel fuels to Moriarty began at the end of calendar 1999. In December 2001, we completed our expansion of the Moriarty terminal and its pumping capacity on the lease pipelines. The terminal expansion included the addition of gasoline and jet fuel to the existing diesel fuel delivery capabilities, thus permitting us to provide a full slate of light products to the growing Albuquerque and Santa Fe, New Mexico area. The enhanced pumping capabilities on the Leased Pipeline extending from the Artesia refinery through Moriarty to Bloomfield will permit us to deliver a total of up to 45,000 BPD of light products to these locations, thereby eliminating third party tariff expenses and the risk of future pipeline constraints on shipments to Albuquerque. If needed, additional pump stations could further increase the pipeline’s 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.

A lawsuit is pending between us and Frontier Oil Corporation.

On August 20, 2003, Frontier Oil Corporation filed a lawsuit in the Delaware Court of Chancery against us seeking declaratory relief and unspecified damages based on allegations that we repudiated our obligations and breached an implied covenant of good faith and fair dealing under a merger agreement announced in late March 2003 under which we and Frontier would be combined. On August 21, 2003, we formally notified Frontier of our position that pending and threatened toxic tort litigation with respect to oil properties operated by a subsidiary of Frontier from 1985 to 1995 adjacent to the campus of Beverly Hills High School constituted a breach of Frontier’s representations and warranties in the merger agreement as to the absence of litigation or other circumstances which could reasonably be expected to have a material adverse effect on Frontier. On September 2, 2003, we filed in the Delaware Court of Chancery our Answer and Counterclaims seeking declaratory judgments that we had not repudiated the merger agreement, that Frontier had repudiated the merger agreement, that Frontier had breached certain representations made by Frontier in the merger agreement, that our obligations under the merger agreement were and are excused and that we may terminate the merger agreement without liability, and seeking unspecified damages as well as costs and attorneys’ fees. A two-week trial in the Delaware Court of Chancery with respect to Frontier’s Complaint and our Answer and Counterclaims was completed in early March 2004. In this litigation, the maximum amount of damages asserted by Frontier against us is approximately $161 million plus interest and the maximum amount of damages we are asserting against Frontier is approximately $148 million plus interest. Post-trial briefing was completed in late April 2004 and in early May 2004 the court heard oral argument. A decision is expected to be announced within several months from the date of this report. Although it is not possible at the date

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of this report to predict the outcome of this litigation, we believe that the claims made by Frontier in the litigation are wholly without merit and that our counterclaims are well founded.

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. In October 2003, the judge before whom the case is pending issued a ruling that denied the Government’s motion for partial summary judgment on all issues raised by the Government and granted our motion for partial summary judgment on most of the issues we raised. The ruling on the motions for summary judgment in our case does not constitute a final ruling on our claims, but instead the judge’s ruling is expected to be followed by substantial discovery proceedings and then a trial on factual issues. The trial judge in our case issued an order in March 2004 to stay proceedings in our case while interlocutory appeals to the United States Court of Appeals for the Federal Circuit are pending on rulings by two other United States Court of Federal Claims judges in cases relating to military fuel sales of two other refining companies. The rulings in these two lower court cases were favorable to the position of the refining company in one case and favorable to the position of the Government in the other case. The appeals court heard oral argument on these related cases in January 2005 and a decision by the appeals court is expected to be issued in the first half of 2005. The appeals court’s decision in the related cases could substantially affect our lawsuit. It is not possible at the date of this report to predict the outcome of further proceedings in our case or the impact on our case of any decisions by the appeals court in the related cases, nor is it possible to predict what amount, if any, will ultimately be payable to us with respect to our lawsuit.

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

New governmental standards on content of refined products could require us to make substantial capital expenditures in order to meet new product standards.

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 federal Clean Air Act, 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.

HEP’s borrowings may limit HEP’s ability to borrow additional funds, comply with the terms of its indebtedness or capitalize on business opportunities.

Following the February 28, 2005 Alon transaction and the issuance of the 6.25% Senior Notes by HEP, HEP’s total outstanding long-term debt, including current maturities, is $150 million. Various limitations in HEP’s revolving credit agreement and the indenture for the notes may reduce HEP’s ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of HEP’s current indebtedness or any new indebtedness could result in similar or greater restrictions.

The instruments governing HEP’s debt contain restrictive covenants that may prevent HEP from engaging in certain beneficial transactions. The agreements governing its debt generally require HEP to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Additionally, an agreement with Alon will restrict HEP from selling the pipelines and terminals acquired from Alon and from prepaying more than $30 million of the 6.25% senior notes for ten years, subject to certain limited exceptions. HEP’s leverage may adversely affect its ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or to otherwise fully realize the value of its assets and opportunities because of the need to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness or to comply with any restrictive terms of its indebtedness. HEP’s leverage may also make its results of operations more susceptible to adverse economic and industry conditions by limiting its flexibility in planning for, or reacting to, changes in its business and the industry in which it operates and may place HEP at a competitive disadvantage as compared to its competitors that have less debt.

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HEP may not be able to realize the expected benefits of its acquisition of Alon’s pipelines and terminals.

HEP’s expectations regarding the revenues and operating cash flow resulting from its acquisition of Alon’s pipelines and terminals may prove to be incorrect. If Alon transports or delivers volumes in amounts equal only to its minimum volume commitment or if Alon is unable to meet its minimum volume commitment for any reason, HEP’s revenues and operating cash flow from these assets will be lower than expected. Furthermore, HEP will be required to obtain Alon’s consent to any third-party shipments on these assets. Even if HEP obtains Alon’s consent, it may not be able to generate significant additional throughput on these assets from third parties other than Alon because the competitive pressures in the markets served by these assets may be greater than anticipated. As a result, HEP revenues and operating cash flow could be adversely affected.

HEP may also face difficulties operating these assets on an efficient basis, resulting in significantly higher costs to HEP than anticipated and thus adversely affecting its revenues and operating cash flow. During the transition of operational control of the assets from Alon to HEP, HEP may experience unforeseen operating difficulties, including difficulties (1) integrating the technological and management standards, processes, procedures and controls of these assets with those of its existing operations; (2) managing the increased scope, geographic diversity and complexity of its operations; and (3) mitigating contingent and/or assumed liabilities.

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 impact 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, is 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.

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 decrease 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, 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 the fiscal year ended July 31, 2001, we entered into energy commodity futures contracts to hedge certain commitments to purchase crude oil and deliver gasoline in March 2001. The purpose of the hedge was to help protect us from the risk that the refined product margins with respect to the hedged gasoline sales would decline.

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Due to the strict requirements of SFAS No. 133 in measuring effectiveness of hedges, this particular hedge transaction did not qualify for hedge accounting. The energy commodity futures contracts entered into resulted in a loss of $0.2 million for the year ended July 31, 2001, which was included in cost of products sold.

During the fiscal year ended July 31, 2001, we entered into commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas in March 2001 and from May 2001 to May 2002. These transactions were designated as cash flow hedges related to the purchase of 1.2 million MMBtu of forecasted natural gas purchases for the Navajo Refinery. At July 31, 2001, a loss of $2.1 million was included in comprehensive income, as the values of the outstanding hedges were marked to the current fair value. In fiscal 2002, we recorded net adjustments of $2.1 million to comprehensive income, which included actual losses of approximately $3.3 million that were reclassified from comprehensive income to operating expenses as the transactions occurred under the swap and collar arrangements.

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 effect 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 the five months ended December 31, 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.

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. At December 31, 2003 there were no ineffective portions of the hedges. 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 at December 31, 2004 no price swaps were outstanding.

At December 31, 2004, we had outstanding unsecured debt of $8.6 million and had $25.0 million of bank borrowings under the HEP credit facility. There were no outstanding bank borrowings under our credit facility at December 31, 2004. At December 31, 2003, we had outstanding unsecured debt of $17.1 million and had $50.0 million of borrowings outstanding under our credit facility. There were no bank borrowings during fiscal 2002 or fiscal 2001. We do not have significant exposure to changing interest rates on our unsecured debt because the interest rates are fixed, the average maturity is less than one year and such debt represents less than 3% of our total capitalization at December 31, 2004. 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 is very low. We used borrowings under our previous credit facility to finance our working capital needs. 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 ten percent change in the market interest rate over the next year would not materially impact our earnings or cash flow since the interest rates on our long-term debt are fixed and our borrowings under the credit facility and investments are at market rates and such interest has historically not been significant as compared to our total operations. A ten percent change in the market interest rate over the next year would not materially impact our financial condition since the average maturity of our unsecured long-term debt is less than one year, such debt represents less than 3% of our total capitalization, and our borrowings under our credit facility and investments are at market rates.

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

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

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

Set forth below is our calculation of EBITDA.

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
                    (In thousands)                  
Net income
  $ 83,879     $ 46,053     $ 32,029     $ 73,450     $ 5,403     $ 18,607  
Add provision for income tax
    54,590       28,306       18,867       48,445       3,114       11,822  
Add interest expense
    3,524       2,136       2,953       4,980       1,014       1,479  
Subtract interest income
    (4,372 )     (458 )     (1,528 )     (2,513 )     (415 )     (963 )
Add depreciation and amortization
    40,481       36,275       27,699       27,327       11,726       10,875  
 
                                   
EBITDA
  $ 178,102     $ 112,312     $ 80,020     $ 151,689     $ 20,842     $ 41,820  
 
                                   

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

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

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

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

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Refinery Gross Margin

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

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Average per produced barrel:
                                               
 
                                               
Navajo Refinery
                                               
Net sales
  $ 51.42     $ 38.95     $ 31.02     $ 39.89     $ 34.93     $ 31.75  
Less cost of products
    41.26       31.52       24.46       30.17       29.44       23.92  
 
                                   
Refinery gross margin
  $ 10.16     $ 7.43     $ 6.56     $ 9.72     $ 5.49     $ 7.83  
 
                                   
 
                                               
Woods Cross Refinery (1)
                                               
Net sales
  $ 51.33     $ 40.91                                  
Less cost of products
    45.33       34.81                                  
 
                                           
Refinery gross margin
  $ 6.00     $ 6.10                                  
 
                                           
 
                                               
Montana Refinery
                                               
Net sales
  $ 43.10     $ 35.80     $ 30.38     $ 36.83     $ 32.18     $ 31.44  
Less cost of products
    35.37       28.17       22.23       26.22       26.01       22.36  
 
                                   
Refinery gross margin
  $ 7.73     $ 7.63     $ 8.15     $ 10.61     $ 6.17     $ 9.08  
 
                                   
 
                                               
Consolidated
                                               
Net sales
  $ 50.80     $ 38.99     $ 30.95     $ 39.60     $ 34.65     $ 31.71  
Less cost of products
    41.70       31.76       24.22       29.80       29.10       23.72  
 
                                   
Refinery gross margin
  $ 9.10     $ 7.23     $ 6.73     $ 9.80     $ 5.55     $ 7.99  
 
                                   


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

Net Operating Margin

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

                                                 
    Years Ended     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Average per produced barrel:
                                               
 
                                               
Navajo Refinery
                                               
Refinery gross margin
  $ 10.16     $ 7.43     $ 6.56     $ 9.72     $ 5.49     $ 7.83  
Less refinery operating expenses
    3.20       3.24       2.84       2.92       2.81       3.20  
 
                                   
Net operating margin
  $ 6.96     $ 4.19     $ 3.72     $ 6.80     $ 2.68     $ 4.63  
 
                                   
 
                                               
Woods Cross Refinery (1)
                                               
Refinery gross margin
  $ 6.00     $ 6.10                                  
Less refinery operating expenses
    3.92       3.92                                  
 
                                           
Net operating margin
  $ 2.08     $ 2.18                                  
 
                                           
 
                                               
Montana Refinery
                                               
Refinery gross margin
  $ 7.73     $ 7.63     $ 8.15     $ 10.61     $ 6.17     $ 9.08  
Less refinery operating expenses
    5.64       5.85       5.55       5.84       5.51       5.23  
 
                                   
Net operating margin
  $ 2.09     $ 1.78     $ 2.60     $ 4.77     $ 0.66     $ 3.85  
 
                                   

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    Years Ended     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Average per produced barrel:
                                               
 
                                               
Consolidated
                                               
Refinery gross margin
  $ 9.10     $ 7.23     $ 6.73     $ 9.80     $ 5.55     $ 7.99  
Less refinery operating expenses
    3.53       3.58       3.13       3.19       3.09       3.47  
 
                                   
Net operating margin
  $ 5.57     $ 3.65     $ 3.60     $ 6.61     $ 2.46     $ 4.52  
 
                                   


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

Below are reconciliations to our 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     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Navajo Refinery
                                               
Average sales price per produced barrel sold
  $ 51.42     $ 38.95     $ 31.02     $ 39.89     $ 34.93     $ 31.75  
Times sales of produced refined products sold (BPD)
    78,880       62,570       59,830       62,620       63,400       52,820  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refined product sales from produced products sold
  $ 1,484,500     $ 889,542     $ 677,413     $ 911,738     $ 338,828     $ 256,586  
 
                                   
 
                                               
Woods Cross Refinery (1)
                                               
Average sales price per produced barrel sold
  $ 51.33     $ 40.91                                  
Times sales of produced refined products sold (BPD)
    23,520       22,480                                  
Times number of days in period
    366       214                                  
 
                                           
Refined product sales from produced products sold
  $ 441,865     $ 196,807                                  
 
                                           
 
                                               
Montana Refinery
                                               
Average sales price per produced barrel sold
  $ 43.10     $ 35.80     $ 30.38     $ 36.83     $ 32.18     $ 31.44  
Times sales of produced refined products sold (BPD)
    7,970       7,150       7,230       6,460       7,080       7,760  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refined product sales from produced products sold
  $ 125,724     $ 93,429     $ 80,171     $ 86,841     $ 34,859     $ 37,328  
 
                                   

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    Years Ended     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Sum of refined product sales from produced products sold from our three refineries (3)
  $ 2,052,089     $ 1,179,778     $ 757,584     $ 998,579     $ 373,687     $ 293,914  
Add refined product sales from purchased products sold and rounding (2)
    167,422       192,805       110,228       120,255       65,700       61,400  
 
                                   
Total refined products sales
    2,219,511       1,372,583       867,812       1,118,834       439,387       355,314  
Add other refining segment revenue
    1,474       823       918       1,414       401       94  
 
                                   
Total refining segment revenue
    2,220,985       1,373,406       868,730       1,120,248       439,788       355,408  
Add pipeline transportation segment sales & other revenue
    23,977       21,030       18,588       18,454       8,245       7,623  
Add corporate and other revenues and eliminations
    1,411       8,808       1,588       3,428       604       823  
 
                                   
Sales and other revenues
  $ 2,246,373     $ 1,403,244     $ 888,906     $ 1,142,130     $ 448,637     $ 363,854  
 
                                   


(1)   We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only 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 where we choose to redirect produced products to more profitable markets.
 
(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     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Average sales prices per produced barrel sold
  $ 50.80     $ 38.99     $ 30.95     $ 39.60     $ 34.65     $ 31.71  
Times sales of produced refined products sold (BPD)
    110,370       82,900       67,060       69,080       70,490       60,580  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refined product sales from produced products sold
  $ 2,052,089     $ 1,179,778     $ 757,584     $ 998,579     $ 373,687     $ 293,914  
 
                                   

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

                                                 
    Years Ended     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Navajo Refinery
                                               
Average cost of products per produced barrel sold
  $ 41.26     $ 31.52     $ 24.46     $ 30.17     $ 29.44     $ 23.92  
Times sales of produced refined products sold (BPD)
    78,880       62,570       59,830       62,620       63,400       52,820  
Times number of days in period.
    366       365       365       365       153       153  
 
                                   
Cost of products for produced products sold
  $ 1,191,180     $ 719,855     $ 534,156     $ 689,575     $ 285,574     $ 193,309  
 
                                   

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    Years Ended     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Woods Cross Refinery (1)
                                               
Average cost of products per produced barrel sold
  $ 45.33     $ 34.81                                  
Times sales of produced refined products sold (BPD)
    23,520       22,480                                  
Times number of days in period
    366       214                                  
 
                                           
Cost of products for produced products sold
  $ 390,215     $ 167,461                                  
 
                                           
 
                                               
Montana Refinery
                                               
Average cost of products per produced barrel sold
  $ 35.37     $ 28.17     $ 22.23     $ 26.22     $ 26.01     $ 22.36  
Times sales of produced refined products sold (BPD)
    7,970       7,150       7,230       6,460       7,080       7,760  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Cost of products for produced products sold
  $ 103,175     $ 73,517     $ 58,664     $ 61,824     $ 28,175     $ 26,548  
 
                                   
 
                                               
Sum of cost of products for produced products sold from our three refineries (3).
  $ 1,684,570     $ 960,833     $ 592,820     $ 751,399     $ 313,749     $ 219,857  
Add refined product costs from purchased products sold and rounding (2)
    169,849       190,939       105,710       120,415       63,966       59,105  
Subtract eliminations with HEP
    (17,917 )                              
 
                                   
Total refining segment costs of products sold
    1,836,502       1,151,772       698,530       871,814       377,715       278,962  
Add (subtract) corporate and other costs and eliminations
    (505 )     4,086       (285 )     (493 )     (177 )     (125 )
 
                                   
Costs of products sold
  $ 1,835,997     $ 1,155,858     $ 698,245     $ 871,321     $ 377,538     $ 278,837  
 
                                   


(1)   We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only 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 where we choose to redirect produced products to more profitable markets.
 
(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     Fiscal Year Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Average cost of products per produced barrel sold.
  $ 41.70     $ 31.76     $ 24.22     $ 29.80     $ 29.10     $ 23.72  
Times sales of produced refined products sold (BPD)
    110,370       82,900       67,060       69,080       70,490       60,580  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Cost of products for produced products sold
  $ 1,684,570     $ 960,833     $ 592,820     $ 751,399     $ 313,749     $ 219,857  
 
                                   

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

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Navajo Refinery
                                               
Average refinery operating expenses per produced barrel sold
  $ 3.20     $ 3.24     $ 2.84     $ 2.92     $ 2.81     $ 3.20  
Times sales of produced refined products sold (BPD)
    78,880       62,570       59,830       62,620       63,400       52,820  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refinery operating expenses for produced products sold
  $ 92,384     $ 73,995     $ 62,020     $ 66,740     $ 27,258     $ 25,861  
 
                                   
 
                                               
Woods Cross Refinery (1)
                                               
Average refinery operating expenses per produced barrel sold
  $ 3.92     $ 3.92                                  
Times sales of produced refined products sold (BPD)
    23,520       22,480                                  
Times number of days in period
    366       214                                  
 
                                           
Refinery operating expenses for produced products sold
  $ 33,745     $ 18,858                                  
 
                                           
 
                                               
Montana Refinery
                                               
Average refinery operating expenses per produced barrel sold
  $ 5.64     $ 5.85     $ 5.55     $ 5.84     $ 5.51     $ 5.23  
Times sales of produced refined products sold (BPD)
    7,970       7,150       7,230       6,460       7,080       7,760  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refinery operating expenses for produced products sold
  $ 16,452     $ 15,267     $ 14,646     $ 13,770     $ 5,969     $ 6,209  
 
                                   
 
                                               
Sum of refinery operating expenses per produced products sold from our three refineries (2)
  $ 142,581     $ 108,120     $ 76,666     $ 80,510     $ 33,227     $ 32,070  
Add other refining segment operating expenses and rounding
    21,137       15,720       13,444       13,013       5,589       5,475  
 
                                   
Total refining segment operating expenses
    163,718       123,840       90,110       93,523       38,816       37,545  
Add pipeline transportation segment operating expenses
    4,380       4,182       6,179       6,501       2,750       2,792  
Add corporate and other costs and eliminations
    166       3,023             386              
 
                                   
Operating expenses (exclusive of depreciation, depletion and amortization)
  $ 168,264     $ 131,045     $ 96,289     $ 100,410     $ 41,566     $ 40,337  
 
                                   


(1)   We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only since the purchase date.
 
(2)   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.

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Table of Contents

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Average refinery operating expenses per produced barrel sold
  $ 3.53     $ 3.58     $ 3.13     $ 3.19     $ 3.09     $ 3.47  
Times sales of produced refined products sold (BPD)
    110,370       82,900       67,060       69,080       70,490       60,580  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refinery operating expenses for produced products sold
  $ 142,581     $ 108,120     $ 76,666     $ 80,510     $ 33,227     $ 32,070  
 
                                   

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

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Navajo Refinery
                                               
Net operating margin per barrel
  $ 6.96     $ 4.19     $ 3.72     $ 6.80     $ 2.68     $ 4.63  
Add average refinery operating expenses per produced barrel
    3.20       3.24       2.84       2.92       2.81       3.20  
 
                                   
Refinery gross margin per barrel
    10.16       7.43       6.56       9.72       5.49       7.83  
Add average cost of products per produced barrel sold
    41.26       31.52       24.46       30.17       29.44       23.92  
 
                                   
Average net sales per produced barrel sold
  $ 51.42     $ 38.95     $ 31.02     $ 39.89     $ 34.93     $ 31.75  
Times sales of produced refined products sold (BPD)
    78,880       62,570       59,830       62,620       63,400       52,820  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refined product sales from produced products sold
  $ 1,484,500     $ 889,542     $ 677,413     $ 911,738     $ 338,828     $ 256,586  
 
                                   
 
                                               
Woods Cross Refinery (1)
                                               
Net operating margin per barrel
  $ 2.08     $ 2.18                                  
Add average refinery operating expenses per produced barrel
    3.92       3.92                                  
 
                                           
Refinery gross margin per barrel
    6.00       6.10                                  
Add average cost of products per produced barrel sold
    45.33       34.81                                  
 
                                           
Average net sales per produced barrel sold
  $ 51.33     $ 40.91                                  
Times sales of produced refined products sold (BPD)
    23,520       22,480                                  
Times number of days in period
    366       214                                  
 
                                           
Refined product sales from produced products sold
  $ 441,865     $ 196,807                                  
 
                                           

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Table of Contents

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Montana Refinery
                                               
Net operating margin per barrel
  $ 2.09     $ 1.78     $ 2.60     $ 4.77     $ 0.66     $ 3.85  
Add average refinery operating expenses per produced barrel
    5.64       5.85       5.55       5.84       5.51       5.23  
 
                                   
Refinery gross margin per barrel
    7.73       7.63       8.15       10.61       6.17       9.08  
Add average cost of products per produced barrel sold
    35.37       28.17       22.23       26.22       26.01       22.36  
 
                                   
Average net sales per produced barrel sold
  $ 43.10     $ 35.80     $ 30.38     $ 36.83     $ 32.18     $ 31.44  
Times sales of produced refined products sold (BPD)
    7,970       7,150       7,230       6,460       7,080       7,760  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refined product sales from produced products sold
  $ 125,724     $ 93,429     $ 80,171     $ 86,841     $ 34,859     $ 37,328  
 
                                   
 
                                               
Sum of refined product sales from purchased products sold from our three refineries (3)
  $ 2,052,089     $ 1,179,778     $ 757,584     $ 998,579     $ 373,687     $ 293,914  
Add refined product sales from purchased products sold and rounding (2)
    167,422       192,805       110,228       120,255       65,700       61,400  
 
                                   
Total refined product sales
    2,219,511       1,372,583       867,812       1,118,834       439,387       355,314  
Add other refining segment revenue
    1,474       823       918       1,414       401       94  
 
                                   
Total refining segment revenue
    2,220,985       1,373,406       868,730       1,120,248       439,788       355,408  
Add pipeline transportation segment sales & other revenues
    23,977       21,030       18,588       18,454       8,245       7,623  
Add corporate and other revenues and eliminations
    1,411       8,808       1,588       3,428       604       823  
 
                                   
Sales and other revenues
  $ 2,246,373     $ 1,403,244     $ 888,906     $ 1,142,130     $ 448,637     $ 363,854  
 
                                   


(1)   We acquired the Woods Cross Refinery on June 1, 2003 and we are reporting amounts for Woods Cross only 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 where we choose to redirect produced products to more profitable markets.
 
(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.

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Table of Contents

                                                 
    Years Ended     Fiscal Years Ended     Five Months Ended  
    December 31,     July 31,     December 31,  
    2004     2003     2002     2001     2002     2001  
Net operating margin per barrel
  $ 5.57     $ 3.65     $ 3.60     $ 6.61     $ 2.46     $ 4.52  
Add average refinery operating expenses per produced barrel
    3.53       3.58       3.13       3.19       3.09       3.47  
 
                                   
Refinery gross margin per barrel
    9.10       7.23       6.73       9.80       5.55       7.99  
Add average cost of products per produced barrel sold
    41.70       31.76       24.22       29.80       29.10       23.72  
 
                                   
Average sales price per produced barrel sold
  $ 50.80       38.99     $ 30.95     $ 39.60     $ 34.65     $ 31.71  
Times sales of produced refined products sold (BPD)
    110,370       82,900       67,060       69,080       70,490       60,580  
Times number of days in period
    366       365       365       365       153       153  
 
                                   
Refined product sales from produced products sold
  $ 2,052,089     $ 1,179,778     $ 757,584     $ 998,579     $ 373,687     $ 293,914  
 
                                   

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Item 8. Financial Statements and Supplementary Data

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

Management of Holly Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the Company’s internal control over financial reporting as of December 31, 2004 using the criteria for effective control over financial reporting established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that, as of December 31, 2004, the Company maintained effective internal control over financial reporting.

The Company’s independent registered public accounting firm has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. That report appears on page 61.

     
Date: March 10, 2005
  /s/ C. Lamar Norsworthy, III
   
  C. Lamar Norsworthy, III
  Chairman of the Board and Chief Executive Officer
 
   
  /s/ Stephen J. McDonnell
   
  Stephen J. McDonnell
  Vice President and Chief Financial Officer

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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, 2004, 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, 2004, 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, 2004, 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, 2004 and 2003, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for the years ended December 31, 2004 and 2003, the five months ended December 31, 2002, and the fiscal year ended July 31, 2002 of Holly Corporation and our report dated March 10, 2005 expressed an unqualified opinion thereon.

     
Dallas, Texas
  /s/  ERNST & YOUNG LLP
March 10, 2005
   

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Table of Contents

Index to Consolidated Financial Statements

     
    Page
    Reference
  63
 
   
  64
 
   
  65
 
   
  66
 
   
  67
 
   
  68
 
   
  69

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
and Stockholders of Holly Corporation

We have audited the accompanying consolidated balance sheets of Holly Corporation as of December 31, 2004 and 2003, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for the years ended December 31, 2004 and 2003, the five months ended December 31, 2002, and the fiscal year ended July 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Corporation at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for the years ended December 31, 2004 and 2003, the five months ended December 31, 2002, and the fiscal year ended July 31, 2002, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Holly Corporation’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 10, 2005 expressed an unqualified opinion thereon.

     
  /s/      ERNST & YOUNG LLP

Dallas, Texas
March 10, 2005

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HOLLY CORPORATION

CONSOLIDATED BALANCE SHEETS

                 
    December 31,     December 31,  
    2004     2003  
    (In thousands, except share data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 67,460     $ 11,690  
Marketable securities
    96,215        
Accounts receivable
    281,730       184,333  
Inventories
    104,968       112,347  
Income taxes receivable
    6,394       7,806  
Prepayments and other
    16,139       12,765  
 
           
Total current assets
    572,906       328,941  
 
Properties, plants and equipment, net
    312,273       304,244  
Marketable securities (long-term)
    55,590        
Investments in and advances to joint ventures
    12,423       13,850  
Other assets
    29,521       59,523  
 
           
 
Total assets
  $ 982,713     $ 706,558  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 377,717     $ 277,897  
Accrued liabilities
    37,975       19,613  
Credit agreement borrowings
          50,000  
Current maturities of long-term debt
    8,572       8,571  
 
           
Total current liabilities
    424,264       356,081  
Deferred income taxes
    20,462       47,492  
Long-term debt, less current maturities
    25,000       8,571  
Other long-term liabilities
    15,521       11,330  
Commitments and contingencies
           
Minority interest
    157,550       14,475  
Stockholders’ equity:
               
Preferred stock, $1.00 par value – 1,000,000 shares authorized; none issued
           
Common stock $.01 par value – 50,000,000 and 20,000,000 shares authorized; 34,804,796 and 16,885,896 shares issued as of December 31, 2004 and 2003, respectively
    348       169  
Additional capital
    29,281       15,818  
Retained earnings
    339,798       264,991  
Accumulated other comprehensive income (loss)
    (1,719 )     130  
Common stock held in treasury, at cost – 3,510,036 and 1,328,868 shares as of December 31, 2004 and 2003, respectively
    (27,792 )     (12,499 )
 
           
Total stockholders’ equity
    339,916       268,609  
 
               
 
           
Total liabilities and stockholders’ equity
  $ 982,713     $ 706,558  
 
           

See accompanying notes.

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Table of Contents

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

                                         
                    Five Months     Fiscal Year     Five Months  
                    Ended     Ended     Ended  
    Years Ended December 31,     December 31     July 31,     December 31  
    2004     2003     2002     2002     2001  
                                    (Unaudited)  
    (In thousands, except per share data)  
Sales and other revenues
  $ 2,246,373     $ 1,403,244     $ 448,637     $ 888,906     $ 363,854  
 
                                       
Operating costs and expenses:
                                       
Cost of products sold (exclusive of depreciation, depletion, and amortization)
    1,835,997       1,155,858       377,538       698,245       278,837  
Operating expenses (exclusive of depreciation, depletion, and amortization)
    168,264       131,045       41,566       96,289       40,337  
Selling, general and administrative expenses (exclusive of depreciation, depletion, and amortization)
    55,428       34,782       9,025       22,248       8,963  
Depreciation, depletion and amortization
    40,481       36,275       11,726       27,699       10,875  
Exploration expenses, including dry holes
    689       1,031       392       1,379       456  
 
                             
Total operating costs and expenses
    2,100,859       1,358,991       440,247       845,860       339,468  
 
                             
Gain on sale of assets
          15,814                    
 
                             
Income from operations
    145,514       60,067       8,390       43,046       24,386  
 
                                       
Other income (expense):
                                       
Equity in earnings of joint ventures
    (318 )     1,398       726       7,753       5,037  
Minority interest in income of partnerships
    (7,575 )     (758 )                  
Interest income
    4,372       458       415       1,528       963  
Interest expense
    (3,524 )     (2,136 )     (1,014 )     (2,953 )     (1,479 )
Reparations payment received
          15,330                    
Other income
                      1,522       1,522  
 
                             
 
    (7,045 )     14,292       127       7,850       6,043  
 
                             
Income before income taxes
    138,469       74,359       8,517       50,896       30,429  
 
                                       
Income tax provision (benefit)
                                       
Current
    79,974       8,009       4,613       14,533       11,572  
Deferred
    (25,384 )     20,297       (1,499 )     4,334       250  
 
                             
 
    54,590       28,306       3,114       18,867       11,822  
 
                             
Net Income
  $ 83,879     $ 46,053     $ 5,403     $ 32,029     $ 18,607  
 
                             
 
                                       
Net income per common share – basic
  $ 2.67     $ 1.49     $ 0.17     $ 1.03     $ 0.60  
 
                             
 
                                       
Net income per common share – diluted
  $ 2.61     $ 1.44     $ 0.17     $ 1.00     $ 0.58  
 
                             
 
                                       
Cash dividends declared per common share
  $ 0.29     $ 0.22     $ 0.055     $ 0.205     $ 0.05  
 
                             
 
                                       
Average number of common shares outstanding:
                                       
Basic
    31,390       31,010       31,032       31,120       31,048  
Diluted
    32,170       32,032       31,804       31,942       31,898  

See accompanying notes.

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Table of Contents

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

                                         
                                Five Months  
                    Five Months     Fiscal Year     Ended  
    Years Ended     Ended     Ended     December 31,  
    December 31,     December 31,     July 31,     2001  
    2004     2003     2002     2002     (Unaudited)  
    (In thousands)  
Cash flows from operating activities:
                                       
Net income
  $ 83,879     $ 46,053     $ 5,403     $ 32,029     $ 18,607  
Adjustments to reconcile net income to net cash provided by operating activities:
                                       
Depreciation, depletion and amortization
    40,481       36,275       11,726       27,699       10,875  
Deferred income taxes
    (25,384 )     20,297       (1,499 )     4,334       250  
Dry hole costs and leasehold impairment
                      289        
Minority interest in income of partnerships
    7,575       758                    
Equity in earnings of joint ventures
    318       (1,398 )     (726 )     (7,753 )     (5,037 )
Equity based compensation expense
    3,419                          
Gain on sale of assets
          (15,814 )                  
(Increase) decrease in current assets:
                                       
Accounts receivable
    (97,397 )     (35,547 )     (12,763 )     10,107       34,734  
Inventories
    7,379       (17,453 )     (15,829 )     4,828       (8,044 )
Income taxes receivable
    6,980       (6,931 )     8,292       (4,731 )     3,514  
Prepayments and other
    (3,908 )     995       (594 )     (4,186 )     469  
Increase (decrease) in current liabilities:
                                       
Accounts payable
    99,029       64,242       22,360       3,876       (27,933 )
Accrued liabilities
    18,024       2,000       (1,570 )     (4,630 )     (1,818 )
Income taxes payable
                      (4,661 )     (4,193 )
Turnaround expenditures
    (7,450 )     (25,029 )     (62 )     (13,931 )     (14,165 )
Prepaid transportation
    25,000             (25,000 )            
Other, net
    7,818       2,308       1,529       (969 )     (1,324 )
 
                             
Net cash provided by (used for) operating activities
    165,763       70,756       (8,733 )     42,301       5,935  
 
                                       
Cash flows from investing activities:
                                       
Additions to properties, plants and equipment
    (37,780 )     (74,642 )     (22,793 )     (35,313 )     (10,405 )
Proceeds from Holly Energy Partners offering
    145,460                          
Holly Energy Partners formation costs
    (3,486 )                        
Purchase Holly Energy Partners restricted units
    (223 )                        
Acquisition of Woods Cross refinery and retail stations
          (55,837 )     (2,500 )            
Investments and advances to joint ventures
    (3,314 )     (3,328 )           (3,250 )      
Purchase of additional interest in joint venture, net of cash
          (21,369 )                  
Distributions from joint ventures
    4,410       4,918       524       11,650       1,150  
Purchases of marketable securities
    (271,720 )                        
Sales and maturities of marketable securities
    119,034                   4,500       4,500  
Proceeds from the sale of partial interest in joint venture
                      460        
Proceeds from sale of pipeline assets
          24,000                    
Proceeds from sale of retail stations
          8,462                    
 
                             
Net cash used for investing activities
    (47,619 )     (117,796 )     (24,769 )     (21,953 )     (4,755 )
 
                                       
Cash flows from financing activities:
                                       
Payment of long-term debt
    (8,570 )     (8,572 )     (8,571 )     (8,572 )     (8,572 )
Net increase (decrease) in borrowings under revolving credit agreements
    (25,000 )     50,000                    
Debt issuance costs
    (3,603 )     (185 )     (635 )            
Issuance of common stock upon exercise of options
    4,655       369       968       1,993       1,450  
Purchase of treasury stock
    (15,293 )     (894 )     (2,210 )     (1,602 )     (160 )
Cash dividends
    (8,281 )     (5,114 )     (3,414 )     (6,377 )     (3,105 )
Cash distributions to minority interests
    (6,282 )     (1,350 )                  
Other
          210                    
 
                             
Net cash provided by (used for) financing activities
    (62,374 )     34,464       (13,862 )     (14,558 )     (10,387 )
 
                                       
Cash and cash equivalents:
                                       
 
                                       
Increase (decrease) for the period
    55,770       (12,576 )     (47,364 )     5,790       (9,207 )
Beginning of period
    11,690       24,266       71,630       65,840       65,840  
 
                             
End of period
  $ 67,460     $ 11,690     $ 24,266     $ 71,630     $ 56,633  
 
                             

See accompanying notes.

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Table of Contents

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

                                                 
                            Accumulated                
                            Other             Total  
    Common     Additional     Retained     Comprehensive     Treasury     Stockholders’  
    Stock     Capital     Earnings     Income (Loss)     Stock     Equity  
    (In thousands)  
Balance at July 31, 2001
  $ 166     $ 11,568     $ 198,118     $ (325 )   $ (7,793 )   $ 201,734  
Net income
                32,029                   32,029  
Dividends
                (6,377 )                 (6,377 )
Other comprehensive income
                      325             325  
Issuance of common stock upon exercise of stock options
    2       1,991                         1,993  
Tax benefit from stock options
          454                         454  
Purchase of treasury stock
                            (1,602 )     (1,602 )
 
                                   
 
                                               
Balance at July 31, 2002
  $ 168     $ 14,013     $ 223,770     $     $ (9,395 )   $ 228,556  
Net income
                5,403                   5,403  
Dividends
                (3,414 )                 (3,414 )
Other comprehensive loss
                      (1,049 )           (1,049 )
Issuance of common stock upon exercise of stock options
          968                         968  
Tax benefit from stock options
          240                         240  
Purchase of treasury stock
                            (2,210 )     (2,210 )
 
                                   
 
                                               
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  
 
                                   

See accompanying notes.

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Table of Contents

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                         
                                Five Months  
                    Five Months     Fiscal Year     Ended  
                    Ended     Ended     December 31,  
    Years Ended December 31,     December 31,     July 31,     2001  
    2004     2003     2002     2002     (Unaudited)  
    (In thousands)  
Net income
  $ 83,879     $ 46,053     $ 5,403     $ 32,029     $ 18,607  
Other comprehensive income (loss)
                                       
Unrealized loss on securities available for sale
    (419 )                        
Reclassification adjustment to net income on sale of equity securities
                      (1,522 )     (1,522 )
Other income (loss) on pension obligation
    (2,006 )     1,362       (1,747 )            
Derivative instruments qualifying as cash flow hedging instruments
                                       
Change in fair value of derivative instruments
    (329 )     373       47       (1,188 )     (1,147 )
Reclassification adjustment into net income
    (270 )     179             3,250       1,749  
 
                             
Total income (loss) on cash flow hedges
    (599 )     552       47       2,062       602  
 
                             
Other comprehensive income (loss) before income taxes
    (3,024 )     1,914       (1,700 )     540       (920 )
Income tax expense (benefit)
    (1,175 )     735       (651 )     215       (355 )
 
                             
Other comprehensive income (loss)
    (1,849 )     1,179       (1,049 )     325       (565 )
 
                             
Total comprehensive income
  $ 82,030     $ 47,232     $ 4,354     $ 32,354     $ 18,042  
 
                             

See accompanying notes.

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Table of Contents

HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

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 has a crude capacity of 75,000 BPSD, can process sour (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. Prior to an expansion completed at the end of 2003, the Navajo facility had a crude capacity of 60,000 BPSD. 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, has a crude capacity of 26,000 BPSD and is operated by Holly Refining & Marketing Company – Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes regional sweet (lower sulfur) and sour Canadian crude oils. We also own Montana Refining Company (“MRC”), which owns an 8,000 BPSD petroleum refinery in Great Falls, Montana (“Montana Refinery”), which can process primarily sour Canadian crude oils and which primarily serves markets in Montana. In conjunction with the refining and pipeline operations, we own approximately 1,000 miles of 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 at December 31, 2004 was owned 51% by us and 49% by other investors in HEP. We consolidate the results of HEP and show the interest we do not own as a minority interest in ownership and earnings. See Note 2 for additional information and for information about changes that have occurred due to the initial public offering of HEP. At December 31, 2004, HEP owned assets including approximately 780 miles of refined product pipelines located principally in West Texas and New Mexico (including 340 miles of leased pipeline); nine refined product terminals (three of which are owned 50% by HEP and 50% by unaffiliated parties) in Albuquerque, Moriarty and Bloomfield, New Mexico; Tucson, Arizona; El Paso, Texas; Burley and Boise, Idaho; Spokane, Washington; and Mountain Home, Idaho; and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which owns a 249-mile pipeline that transports liquid petroleum gases, or LPG’s, from West Texas to the Texas/Mexico border near El Paso for further transport into Northern Mexico. See Note 27 for information on HEP’s purchase of assets from Alon USA, Inc. and certain of its affiliates (collectively “Alon”) effective February 28, 2005, which reduced our ownership interest in HEP to 47.9%.

At December 31, 2004, we also had a 49% interest (50% prior to January 1, 2002) in NK Asphalt Partners, which manufactures and markets asphalt and asphalt products in Arizona and New Mexico. See Note 27 for information regarding the purchase we made in February 2005 of our other partner’s 51% interest giving us a 100% ownership interest. 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 this investment in February 2005.

Change in Year-End: On July 30, 2003, we changed our fiscal year from a July 31 fiscal year-end to a December 31 year-end. A transition report on Form 10-Q was filed for the period August 1, 2002 to December 31, 2002.

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 Rio Grande were consolidated as of June 30, 2003.

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.

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Table of Contents

HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

Reclassifications: Certain reclassifications have been made to prior period balances to conform to the classifications used in 2004.

Cash Equivalents: For purposes of the statement of cash flows, 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: For purposes of the statement of cash flows, we consider all highly-rated 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.

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, 2004 and 2003, the five months ended December 31, 2002, or the fiscal year ended July 31, 2002.

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.

Prepaid Transportation Costs: In November 2002, as a result of our settlement of litigation with Longhorn Partners Pipeline, L.P. (“Longhorn Partners”), we prepaid $25.0 million to Longhorn Partners for the shipment of 7,000 BPD of refined products from the Gulf Coast to El Paso for a period of up to six years from the date the Longhorn Pipeline began operations, if such operations began by July 1, 2004. Under the agreement, the prepayment would cover our shipment of 7,000 BPD for approximately four and a half years assuming there were no curtailments of service once operations began. On July 1, 2004, we received $27.2 million from Longhorn Partners which represents the $25.0 million principal and $2.2 million interest from Longhorn partners. This repayment resulted in a termination of our transportation rights under the November 2002 settlement agreement.

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 16 years for refining and pipeline terminal facilities, 23 to 33 years for certain regulated pipelines and 3 to 10 years for corporate and other assets.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

Cost Classifications: Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. Crude oil buy/sell exchanges are often utilized in getting the desired crude oil to the refineries. In addition, we 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. 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 and other direct operating costs. Selling, general and administrative expenses include compensation, marketing expense, 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.

Oil and Gas Exploration and Development: We account for the acquisition, exploration, development and production costs of our oil and gas activities using the successful efforts method of accounting. Lease acquisition costs are capitalized while undeveloped leases are written down when determined to be impaired and written off upon expiration or surrender. Geological and geophysical costs and delay rentals are expensed as incurred. Exploratory well costs are initially capitalized, but if the effort is unsuccessful, the costs are charged against earnings. Development costs, whether or not successful, are capitalized. Productive properties are stated at the lower of amortized cost or estimated realizable value of underlying proved oil and gas reserves. Depreciation, depletion and amortization of such properties is computed by the units-of-production method. At December 31, 2004 and 2003, we did not own a material amount of proven reserves.

Stock-Based Compensation: Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation” encourages companies to adopt a fair value approach to valuing stock options that would require compensation cost to be recognized based on the fair value of stock options granted. We have elected, as permitted by the standard, to continue to follow the intrinsic value based method of accounting for stock options consistent with Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value method, compensation cost for stock options is measured as the excess, if any, of the quoted market price of our stock at the measurement date over the exercise price. We have adopted the disclosure-only provision of SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure.”

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
(Information for the five month period ended December 31, 2001 is unaudited)

Derivative Instruments: Effective as of August 1, 2000, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. This standard established accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivative instruments be recognized as either assets or liabilities in the balance sheet and be measured at their fair value. The standard requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 17 for additional information on derivative instruments and hedging activities.

New Accounting Pronouncements:

In December 2003, the FASB issued SFAS No. 132 (revised), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This revision requires additional disclosures in annual reports concerning the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. Additionally, the standard now requires interim period disclosures regarding net periodic pension cost and employer contributions. The standard is effective for fiscal years ending after December 15, 2003. We adopted the standard on December 31, 2003.

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. This standard will be effective for us for the first interim period beginning after June 15, 2005. We do not believe the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows.

In December 2004, the FASB issued FASB 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 will be effective for fiscal years beginning after June 15, 2005. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements.

NOTE 2: Initial Public Offering of Holly Energy Partners

On March 15, 2004, we filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of limited partnership units in HEP. 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.

On July 7, 2004, HEP priced 6,100,000 common units for the initial public offering and on July 8, 2004, HEP’s common units began trading on the New York Stock Exchange under the symbol “HEP.” 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. Proceeds to HEP from the sale of the units were $145.5 million, net of underwriting commissions. After such 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 the sale by us of a 49% interest in HEP.

In July 2004, HEP repaid Holly Corporation for $30.1 million of debt and made a distribution to Holly Corporation of $125.6 million. Beginning with the third quarter of 2004, we consolidate the results of HEP with minority interest treatment for the common units.

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 the other limited partners to receive such distributions.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

In connection with the offering, 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 will initially be $35.4 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.

The following table sets forth the changes in the minority interest balance attributable to third party investors’ interests in HEP subsequent to its initial public offering. The opening balance represents our minority interest in Rio Grande Pipeline Company (“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
    6,538  
Cash distribution to minority interests
    (4,032 )
Purchase HEP restricted units
    (223 )
Other
    30  
 
     
Minority interest at December 31, 2004
  $ 157,550  
 
     

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:

                                         
                    Five Months     Fiscal     Five Months  
                    Ended     Year Ended     Ended  
    Years Ended December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
    (In thousands, except per share data)  
Net income
  $ 83,879     $ 46,053     $ 5,403     $ 32,029     $ 18,607  
 
                                       
Average number of shares of common stock outstanding
    31,390       31,010       31,032       31,120       31,048  
Effect of dilutive stock options and variable restricted shares
    780       1,022       772       822       850  
 
                             
Average number of shares of common stock outstanding assuming dilution
    32,170       32,032       31,804       31,942       31,898  
 
                             
 
                                       
Income per share – basic
  $ 2.67     $ 1.49     $ 0.17     $ 1.03     $ 0.60  
 
                             
 
                                       
Income per share – diluted
  $ 2.61     $ 1.44     $ 0.17     $ 1.00     $ 0.58  
 
                             

NOTE 4: Stock-Based Compensation

We have compensation plans under which certain officers and employees have been granted stock options. 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. Our stock-based compensation is measured in accordance with the

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

provisions of Accounting Principles Board Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees” and related interpretations. Accordingly, no compensation expense is recognized for fixed option plans because the exercise prices of employee stock options equal or exceed the market prices of the underlying stock on the dates of grant.

As required by SFAS No. 123, we have determined pro-forma information as if we had accounted for stock options granted under the fair value method of SFAS No. 123. The weighted-average fair value of options granted was $2.13 per share in fiscal 2002 and $1.59 per share in fiscal 2001. There have been no options granted since July 2002. The Black-Scholes option pricing model was used to estimate the fair value of options at the respective grant date with the following weighted-average assumptions:

                 
    Fiscal Years Ended  
    July 31,  
    2002     2001  
Risk-free interest rates
    4.8 %     4.9 %
Dividend yield
    3.0 %     3.0 %
Expected common stock market price volatility factor
    49.6 %     32.0 %
Weighted-average expected life of options
  6 years   6 years

The pro-forma effect of these options on net income and basic and diluted income per share is as follows:

                                         
                    Five Months     Fiscal     Five Months  
                    Ended     Year Ended     Ended  
    Years Ended December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
    (In thousands, except per share data)  
Net income, as reported
  $ 83,879     $ 46,053     $ 5,403     $ 32,029     $ 18,607  
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects
    371       453       189       465       202  
 
                             
Pro forma net income
  $ 83,508     $ 45,600     $ 5,214     $ 31,564     $ 18,405  
 
                             
 
Net income per share – basic
                                       
As reported
  $ 2.67     $ 1.49     $ 0.17     $ 1.03     $ 0.60  
Pro forma
  $ 2.66     $ 1.47     $ 0.17     $ 1.01     $ 0.60  
 
                                       
Net income per share – diluted
                                       
As reported
  $ 2.61     $ 1.44     $ 0.17     $ 1.00     $ 0.58  
Pro forma
  $ 2.60     $ 1.42     $ 0.17     $ 0.99     $ 0.58  

During the year ended December 31, 2004 we issued 271,094 shares (net of forfeitures) of restricted stock under our Long Term Incentive Compensation Plan. Of the 271,094 shares issued, 74,450 shares vested in January or February 2005 and 74,450 shares are scheduled to vest on or after January 1, 2006 (with later performance-based vesting after January 1, 2006 in the case of shares granted to certain key executives). The remaining 122,194 shares vest 33.3% on January 1, 2007, 33.3% on January 1, 2008 and 33.4% on January 1, 2009 (with later performance-based vesting in the case of shares granted to certain key executives). We also issued 17,010 shares of restricted stock to outside directors with these shares vesting on the date of the Annual Meeting of Stockholders in 2007. Although ownership in these shares will not transfer to the recipients until the shares vest, recipients have dividend and voting rights on these shares from the date of grant. We are recording the cost of these grants over their corresponding vesting periods and have expensed $3.4 million for the year ended December 31, 2004.

During the year ended December 31, 2004, we also granted 277,350 performance share units (net of forfeitures) under our Long Term Incentive Compensation Plan. Of the 277,350 units issued, 162,900 units (net of forfeitures) vested on January 1, 2005. The remaining 114,450 units (net of forfeitures) generally vest on January 1, 2007. The

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

cash benefit payable under these grants is based upon our share price and upon our total shareholder return during the period as compared to the total shareholder return of our peer group of refining companies. We are recording the cost of these grants over their corresponding vesting periods and have expensed $8.4 million for the year ended December 31, 2004.

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.

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.

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 primarily invested in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings.

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, 2004:

                         
    Available-for-Sale Securities  
                    Estimated  
            Gross     Fair Value  
            Unrealized     (Net Carrying  
    Amortized Cost     Losses     Amount)  
    (Dollars 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  
 
                 

During the year ended December 31, 2004, we recognized less than $0.1 million in losses related to 61 sales and maturities where we received $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
(Information for the five month period ended December 31, 2001 is unaudited)

NOTE 6: Accounts Receivable

                 
    December 31,  
    2004     2003  
    (In thousands)  
Product and transportation
  $ 105,998     $ 68,662  
Crude oil resales
    175,732       115,671  
 
           
 
  $ 281,730     $ 184,333  
 
           

Crude oil resales accounts receivable 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,  
    2004     2003  
    (In thousands)  
Crude oil
  $ 20,213     $ 34,545  
Other raw materials and unfinished products (1)
    13,718       14,006  
Finished products (2)
    58,613       52,098  
Process chemicals (3)
    4,206       4,842  
Repairs and maintenance supplies and other
    8,218       6,856  
 
           
 
  $ 104,968     $ 112,347  
 
           


(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 $78.7 million and $39.9 million at December 31, 2004 and 2003, respectively. We recognized $4.9 million and $2.3 million in income in the year ended December 31, 2004 and the fiscal year ended July 31, 2002, respectively, resulting from liquidations of certain LIFO inventory quantities that were carried at lower costs as compared to current costs. There were no LIFO inventory adjustments for the year ended December 31, 2003, and the five month periods ended December 31, 2002 and 2001.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

NOTE 8: Properties, Plants and Equipment

                 
    December 31,  
    2004     2003  
    (In thousands)  
Land, buildings and improvement
  $ 20,656     $ 19,501  
Refining facilities
    348,817       335,483  
Pipelines and terminals
    142,450       137,785  
Transportation vehicles
    22,203       18,846  
Oil and gas exploration and development
    3,635       5,084  
Other fixed assets
    16,675       15,219  
Construction in progress
    17,711       3,997  
 
           
 
    572,147       535,915  
Accumulated depreciation, depletion and amortization
    (259,874 )     (231,671 )
 
           
 
  $ 312,273     $ 304,244  
 
           

We did not capitalize any interest for the year ended December 31, 2004. We capitalized interest related to major construction projects of $1.2 million for the year ended December 31, 2003, $0.7 million for the five months ended December 31, 2002, $1.1 million for the year ended July 31, 2002 and $0.4 million for the five months ended December 31, 2001.

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 liquid petroleum gases (“LPG’s”) from a point near Odessa, Texas to Pemex Gas (“Pemex”) at a point near El Paso, Texas. Pemex 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 consolidated 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.

NK Asphalt Partners, a joint venture which was owned 49% by us and 51% by a subsidiary of Koch Materials Company (“Koch”) at December 31, 2004, manufactures and markets asphalt products from various terminals in Arizona and New Mexico under the name “Koch Asphalt Solutions – Southwest.” We accounted for this investment using the equity method. Prior to January 2002, we owned 50% and Koch owned 50% of the joint venture. Effective January 2002, we sold 1% of our 50% equity interest to Koch. As part of the joint venture agreement, we were required to make additional contributions to the joint venture of up to $3.25 million for each of the next six years contingent on the earnings level of the joint venture. A contribution of $3.25 million was made July 2004. In February 2005, we purchased the 51% interest owned by Koch in NK Asphalt Partners for $16.9 million plus approximately $5 million for 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 the remaining annual $3.25 million payments. All asphalt produced at our Navajo Refinery is sold at market prices to the joint venture under a supply agreement. Sales to the joint venture during the years ended December 31, 2004 and 2003, five months ended December 31, 2002 and 2001 and year ended July 31, 2002 were $32.2 million, $31.0 million, $11.1 million, $9.2 million and $22.6 million, respectively.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

NK Asphalt Partners Joint Venture (Unaudited):

                                         
                    Five Months     Fiscal     Five Months  
                    Ended     Year Ended     Ended  
    Years Ended December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
    (In thousands)  
Current assets
  $ 14,237     $ 15,379     $ 22,050     $ 24,631     $ 30,801  
Other assets
    11,581       12,739       13,095       13,263       13,927  
 
                             
Total
  $ 25,818     $ 28,118     $ 35,145     $ 37,894     $ 44,728  
 
                             
 
                                       
Current liabilities
  $ 6,165     $ 4,613     $ 6,048     $ 8,878     $ 6,290  
Long-term liabilities
    9       23       35       51       45  
Equity
    19,644       23,482       29,062       28,965       38,393  
 
                             
Total
  $ 25,818     $ 28,118     $ 35,145     $ 37,894     $ 44,728  
 
                             
 
                                       
Sales (net)
  $ 99,140     $ 96,380     $ 33,713     $ 86,596     $ 42,310  
 
                             
Gross Profit
  $ 17,311     $ 14,184     $ 4,667     $ 22,918     $ 11,275  
 
                             
Income from operations
  $ 4,718     $ 2,603     $ 824     $ 13,217     $ 6,953  
 
                             
Net income before taxes
  $ 1,912     $ 1,170     $ 97     $ 13,425     $ 9,103  
 
                             

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 will result in a book gain to us of $0.5 million.

NOTE 10: Other Assets

                 
    December 31,  
    2004     2003  
    (In thousands)  
Prepaid transportation costs
  $     $ 25,000  
Turnaround costs (long-term portion)
    13,535       18,909  
Intangibles and other
    15,986       15,614  
 
           
 
  $ 29,521     $ 59,523  
 
           

NOTE 11: Environmental Costs

Consistent with our accounting policy for environmental remediation and cleanup costs, we expensed $0.8 million and $3.9 million in 2004 and 2003, respectively, for environmental remediation and cleanup obligations. In the previous periods reported, our remediation and cleanup obligations were expensed as incurred. The accrued environmental liability reflected in the consolidated balance sheet was $3.6 million and $4.0 million at December 31, 2004 and 2003, respectively, of which $2.4 million and $2.2 million was classified as other long-term liabilities, respectively. Costs of future expenditures for environmental remediation are not discounted to their present value.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

NOTE 12: Debt

                 
    December 31,  
    2004     2003  
    (In thousands)  
Senior Notes
               
Series C
  $ 5,572     $ 11,142  
Series D
    3,000       6,000  
 
           
 
    8,572       17,142  
 
               
Credit agreement facility
               
Holly Corporation
          50,000  
HEP
    25,000        
 
           
 
    25,000       50,000  
 
               
Total debt
    33,572       67,142  
 
               
Credit facility borrowings classified as current
          (50,000 )
Current maturities of long-term debt
    (8,572 )     (8,571 )
 
           
Total debt classified as long-term
  $ 25,000     $ 8,571  
 
           

Senior Notes: In November 1995, we completed the funding from a group of insurance companies of a new private placement of Senior Notes in the amount of $39.0 million and the extension of $21.0 million of previously outstanding Senior Notes. The $39.0 million Series C Notes have a 10-year life, require equal annual principal payments beginning December 15, 1999, and bear interest at 7.62%. The $21.0 million Series D Notes, have a 10-year life, require equal annual principal payments beginning December 15, 1999, and bear interest at an initial rate of 10.16%, with reductions to 7.82% for the periods subsequent to June 15, 2001. The senior notes are unsecured and the note agreements impose certain restrictive covenants, including limitations on liens, additional indebtedness, sales of assets, investments, business combinations and dividends, which collectively are less restrictive than the terms of the bank Credit Facility. We were in compliance with all covenants at December 31, 2004.

Credit Facilities: 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 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 was payable on the outstanding balance of all letters of credit and a commitment fee ranging from 0.30% to 0.50% per annum was 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 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, 2004. At December 31, 2004, we had outstanding letters of credit totaling $1.2 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our current credit facility was $173.8 million at December 31, 2004.

Our prior revolving credit facility was entered into in April 2000 and amended and increased the commitment from $75 million to $100 million in May 2003 giving us access to $100 million of commitments that could be used for revolving credit loans and letters of credit. At December 31, 2003, we had outstanding letters of credit totaling $4.2 million and $50.0 million in borrowings outstanding under our prior revolving credit facility. At that level of usage, the unused commitment under the prior credit facility was $45.8 million at December 31, 2003.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

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 obligations under HEP’s credit facility are secured by substantially all of their assets, and such obligations are non-recourse to our general partner interest in HEP. Interest on the borrowings of HEP is based upon, at their option, either (i) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (ii) at a rate equal to LIBOR plus an applicable margin (ranging from 1.50% to 2.25%). In each case, the applicable margin is based upon the ratio of funded debt to EBITDA. HEP incurs a commitment fee on the unused portion of the credit facility at a rate of 0.375% or 0.500% based upon the ratio of funded debt to EBITDA for the four most recently completed fiscal quarters. The facility matures in July 2008. At that time, the agreement will terminate and all outstanding amounts will be due and payable. HEP’s credit facility contains certain compliance covenants and imposes certain restrictions on distributions to unitholders, their ability to incur debt, make loans, acquire other companies, change the nature of their business, enter a merger or consolidation, or sell assets. HEP was in compliance with its covenants at December 31, 2004. At December 31, 2004, $25.0 million was drawn under the facility which was outstanding since the initial public offering of HEP. At that level of usage, the unused commitment under HEP’s credit facility was $75.0 million at December 31, 2004.

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

                 
    December 31,  
    2004     2003  
Average amount outstanding
  $ 15,888     $ 15,879  
Maximum balance
  $ 80,000     $ 65,000  
Effective average interest rate
    2.9 %     2.7 %

There were no borrowings outstanding under the previous credit facility during the five months ended December 31, 2002 or the fiscal year ended July 31, 2002.

The senior notes and credit facility restrict investments and distributions, including dividends. Under the most restrictive of these covenants, under the credit facility, we are able to pay dividends at the current rate for the foreseeable future.

Long-term debt outstanding under the senior notes as of December 31, 2004 matures in 2005. The $25.0 million borrowings drawn under HEP’s credit facility are not a working capital borrowing under the credit facility and may be extended and renewed at our option; therefore, the outstanding borrowings have been classified as long-term.

We made cash interest payments of $2.7 million for the years ended December 31, 2004 and 2003, $1.7 million in the five months ended December 31, 2002, $3.8 million for the year ended July 31, 2002 and $2.1 million for the five months ended December 31, 2001.

Based on the borrowing rates we believe would be available for replacement loans with similar terms and maturities of our debt now outstanding, we estimate the fair value of long-term debt including current maturities (excluding borrowings under HEP’s credit facility that are designated as long-term borrowings) to be approximately equal to the amount currently on the balance sheet of $8.6 million at December 31, 2004.

See Note 27 for information on HEP’s private offering of $150 million principal amount of 6.25% senior notes due 2015 which closed on February 28, 2005. The use of proceeds was to finance HEP’s acquisition of assets from Alon and to repay borrowings under the HEP credit facility.

Although debt of HEP is reflected on our balance sheet (because HEP is a consolidated subsidiary) for dates when the debt is outstanding, Holly Corporation and its operating subsidiaries, other than HEP and its subsidiaries and controlling partners, are not liable on this debt either directly or as guarantors.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

NOTE 13: Income Taxes

The provision for income taxes is comprised of the following:

                                         
                    Five Months     Fiscal Year     Five months  
    Year Ended     Ended     Ended     Ended  
    December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
    (In thousands)  
Current
                                       
Federal
  $ 66,209     $ 6,720     $ 4,266     $ 12,317     $ 10,415  
State
    13,765       1,289       347       2,216       1,157  
Deferred
                                       
Federal.
    (20,777 )     17,433       (1,187 )     4,072       235  
State
    (4,607 )     2,864       (312 )     262       15  
 
                             
 
  $ 54,590     $ 28,306     $ 3,114     $ 18,867     $ 11,822  
 
                             

The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows:

                                         
                    Five Months     Fiscal Year     Five Months  
                    Ended     Ended     Ended  
    Year Ended     December 31,     December 31,     July 31,     December 31,  
    2004     2003     2002     2002     2001  
    (In thousands)  
Tax computed at statutory rate
  $ 48,464     $ 26,026     $ 2,981     $ 17,814     $ 10,650  
State income taxes, net of federal tax benefit
    5,400       2,658       332       1,985       1,186  
Other
    726       (378 )     (199 )     (932 )     (14 )
 
                             
 
  $ 54,590     $ 28,306     $ 3,114     $ 18,867     $ 11,822  
 
                             

Prior to our acquisition of MRC, operations of the corporation that was the sole limited partner of MRC resulted in unused net operating loss carryforwards of approximately $9.0 million, which are expected to be available to us to a limited extent each year through 2006. As of December 31, 2004, approximately $0.8 million of these net operating loss carryforwards remain available to offset future income. In fiscal 2002, we recognized a benefit of approximately $0.5 million associated with these net operating loss carryforwards. For financial reporting purposes, the unrecognized portion of the benefit of these net operating loss carryforwards is being offset against contingent future payments of up to $0.1 million per year through 2005 relating to the acquisition of such corporation.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information for the five month period ended December 31, 2001 is unaudited)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amount used for income tax purposes. Our deferred income tax assets and liabilities as of December 31, 2004 and 2003 are as follows:

                         
    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 )