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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, 2003

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 American 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, 2003 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $252,000,000. (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.)

15,619,778 shares of Common Stock, par value $.01 per share, were outstanding on March 1, 2004.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 13, 2004, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2003, are incorporated by reference in Part III.



 


TABLE OF CONTENTS

             
Item
  Page
PART I
Forward-Looking Statements   3
Definitions  
 
    4  
1 & 2.       5  
3.       20  
4.       21  
PART II
5.       22  
6.       23  
7.       24  
7A.       43  
Reconciliations to amounts reported under generally accepted accounting principles 43
8.       46  
9.       78  
9A.       78  
PART III
10.       78  
11.       78  
12.       78  
13.       78  
14.       79  
PART IV
15.       79  
Signatures  
 
    81  
Index to exhibits 83
 Subsidiaries of Registrant
 Consent of Independent Auditors
 Certification of CEO under Section 302
 Certification of CFO under Section 302
 Certification of CEO under Section 906
 Certification of CFO under 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. Such 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 the Company believes that the expectations reflected in such forward-looking statements are reasonable, the Company cannot give any assurances that those expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Such 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 the Company’s 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 financing to the Company;
 
    the effectiveness of the Company’s capital investments and marketing strategies;
 
    the Company’s efficiency in carrying out construction projects;
 
    the outcome of the litigation with Frontier Oil Corporation;
 
    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 the Company’s Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from the Company’s 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 the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and the Company undertakes 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.

     “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 liquids, 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” 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.

     “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.

     “Refining gross margin” or “refinery gross margin” means the difference between produced refined product sales prices and the costs for crude oil and other feedstocks.

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

     “Sour crude oil” means crude oil containing appreciable quantities of hydrogen sulfide or other sulfur compounds.

     “Vacuum distillation” means the process of distilling vapor from liquids, 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

Holly Corporation (including its consolidated and wholly-owned subsidiaries unless the context otherwise indicates, the “Company”), is principally an independent petroleum refiner, which produces high value light products such as gasoline, diesel fuel and jet fuel. The Company was incorporated in Delaware in 1947 and maintains its principal corporate offices at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6927. The telephone number of the Company is 214-871-3555, and its internet website address is www.hollycorp.com. The information contained on the 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 the filings of the Company at the U.S. Securities and Exchange Commission (“SEC”) web site is available on the Company’s website on the Investors Relations page.

The Company

    owns and operates three refineries consisting of a petroleum refinery in Artesia, New Mexico that is operated in conjunction with crude oil 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;
 
    owns and operates nine refined product storage terminals in Artesia, Moriarty, Bloomfield and Lovington, New Mexico; El Paso, Texas; Woods Cross, Utah; Great Falls, Montana; Spokane, Washington; and Mountain Home, Idaho;
 
    owns interests in four refined product storage terminals in Albuquerque, New Mexico; Tucson, Arizona; and Burley and Boise, Idaho; and
 
    owns or leases approximately 2,000 miles of pipeline located principally in west Texas and New Mexico.

Navajo Refining Company, L.P., one of the Company’s wholly-owned subsidiaries, owns the Navajo Refinery. The Navajo Refinery has a crude capacity of 75,000 BPD, can process a variety of 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 BPD. In June, 2003, the Company acquired the Woods Cross refining facility from ConocoPhillips. The Woods Cross refinery (“Woods Cross Refinery”), located just north of Salt Lake City, has a crude capacity of 25,000 BPD and is operated by Holly Refining & Marketing Company, one of the Company’s wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes sweet (lower sulfur) crude oil. The Company also owns Montana Refining Company, a Partnership, which owns a 7,000 BPD petroleum refinery in Great Falls, Montana (“Montana Refinery”), which can process a variety of sour crude oils and which primarily serves markets in Montana. In conjunction with the refining operations, the Company owns or leases approximately 1,700 miles of pipelines that serve primarily as the supply and distribution network for the Company’s refineries.

In recent years, the Company has made an effort to develop and expand a pipeline transportation business generating revenues from unaffiliated parties. Pipeline transportation operations currently include approximately 500 miles of pipeline, of which approximately 200 miles are also part of the supply and distribution network of the Navajo Refinery. The Company’s pipeline transportation business and refinery operation combined consist of 2,000 miles of pipelines that the Company owns or leases. Additionally, the Company owns a 70% interest in Rio Grande Pipeline Company, which provides transportation of LPG to northern Mexico, and a 49% interest in NK Asphalt Partners, which manufactures and markets asphalt and asphalt products in Arizona and New Mexico. In addition to its refining and pipeline transportation operations, the Company also conducts a small-scale oil and gas exploration and production program and has a small investment in a joint venture conducting a retail gasoline station and convenience store business in Montana.

The Company’s operations are currently organized into two business divisions, which are Refining and Pipeline Transportation. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and the Company’s interest in the NK Asphalt Partners joint venture. Operations of the Company that are not included in either the Refining or Pipeline Transportation business divisions include the operations of Holly Corporation, the parent company, as well as oil and gas operations and the Company’s investment in the Montana retail gasoline joint venture. The accompanying discussion of the Company’s business and properties reflects this organizational structure.

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On July 30, 2003, the Company changed its 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 the Company’s change in year-end.

REFINERY OPERATIONS

The Company’s refinery operations include the Navajo Refinery, the Woods Cross Refinery, and the Montana Refinery.

The following table sets forth certain information about the combined refinery operations of the Company:

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
Crude charge (BPD)(1)
    76,040       64,300       60,200       64,020  
Refinery production (BPD)(2)
    85,030       73,600       66,360       69,640  
Sales of produced refined products (BPD)
    82,900       71,210       67,060       69,080  
Sales of refined products (BPD)(3)
    95,420       80,180       76,420       77,000  
Refinery utilization(4)
    93.2 % (5)     96.0 %     89.9 %(5)     95.6 %
Average per produced barrel(6)
                               
Net sales
  $ 38.99     $ 32.22     $ 30.95     $ 39.60  
Raw material costs
    31.76       26.38       24.22       29.80  
 
   
 
     
 
     
 
     
 
 
Refinery gross margin
    7.23       5.84       6.73       9.80  
Refinery operating expenses(7)
    3.58       2.99       3.13       3.19  
 
   
 
     
 
     
 
     
 
 
Net cash operating margin
  $ 3.65     $ 2.85     $ 3.60     $ 6.61  
 
   
 
     
 
     
 
     
 
 

  (1)   Crude charge represents the barrels per day of crude oil processed at the crude units at the Company’s 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 the Company’s refineries.
 
  (3)   Includes refined products purchased for resale representing 12,520 BPD, 8,970 BPD, 9,360 BPD, and 7,920 BPD, respectively.
 
  (4)   Crude charge divided by total crude capacity of 67,000 BPD through May 2003, and 92,000 BPD through December 2003 which reflects the acquisition of the Woods Cross Refinery in June 2003.
 
  (5)   Refinery utilization rate reflects the effects of turnarounds for major maintenance at the Navajo Refinery and the Woods Cross Refinery in 2003 and the Navajo Refinery in fiscal 2002.
 
  (6)   Represents average per barrel amounts for produced refined products sold. Reconciliations to amounts reported under generally accepted accounting principles (“GAAP”) are located under “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
  (7)   Represents operating expenses of refineries, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

The petroleum refining business is highly competitive. Among the Company’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. The Company also competes with other independent refiners. Competition in a particular geographic area is affected primarily by the amount of refined products produced by refineries located in such area and by the

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availability of refined products and the cost of transportation to such area from refineries located outside the area. Projects have been explored from time to time by refiners and other entities, which projects, if consummated, could result in further increases in the supply of products to some or all of the Company’s markets. In recent years, there have been several refining and marketing consolidations or acquisitions between entities competing in the Company’s geographic markets. These transactions could increase future competitive pressures on the Company.

Set forth below is certain information regarding the principal products of the Company:

                                                                 
    Years ended December 31,
  Fiscal Years ended July 31,
    2003
  2002
  2002
  2001
    BPD
  %
  BPD
  %
  BPD
  %
  BPD
  %
Sales of produced refined products
                                                               
Gasolines
    47,290       57.0 %     40,660       57.1 %     37,740       56.3 %     38,740       56.1 %
Diesel fuels
    19,060       23.0 %     15,070       21.2 %     14,050       20.9 %     15,100       21.8 %
Jet fuels
    6,220       7.5 %     7,460       10.5 %     7,090       10.6 %     7,440       10.8 %
Asphalt
    6,760       8.2 %     5,490       7.7 %     5,820       8.7 %     5,260       7.6 %
LPG and other
    3,570       4.3 %     2,530       3.5 %     2,360       3.5 %     2,540       3.7 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Total
    82,900       100.0 %     71,210       100.0 %     67,060       100.0 %     69,080       100.0 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

Approximately 4% of the Company’s revenues in 2003 resulted from the sale for export of gasoline and diesel fuel to an affiliate of PEMEX. Approximately 6% of the Company’s revenues in 2003 resulted from the sale of military jet fuel to the United States Government. The loss of the Company’s military jet fuel contract with the United States Government could have an adverse effect on the Company’s 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 is a purchaser of gasoline that supplies its retail network and accounted for approximately 12% of the Company’s revenues in 2003. ConocoPhillips is a purchaser of gasoline and diesel fuel that supplies its branded retail network and accounted for approximately 12% of the Company’s revenues in 2003. Loss of, or reduction in amounts purchased by, major current purchasers for retail sales could have a material adverse effect on the Company to the extent that, because of market limitations or transportation constraints, the Company was not able to correspondingly increase sales to other purchasers. The Company believes that the availability of significant capacity in its pipeline transportation system to the Albuquerque area and northern New Mexico increases the Company’s 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 its refineries, the Company must continually enter into contracts for new crude oil supplies. The primary factors affecting the Company’s ability to contract for new crude oil supplies is its ability to connect new supplies of crude oil to its gathering systems or to its other crude oil receiving lines, its 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 its gathering systems or its other crude oil receiving lines.

Navajo Refinery

Facilities

With the recently completed expansion and upgrade project, the Navajo Refinery now has a crude oil capacity of 75,000 BPD and has the ability to process a variety of sour crude oils into high value light products (such as gasoline, diesel fuel and jet fuel). The Navajo Refinery’s processing capabilities enable management to vary the crude supply mix to take advantage of changes in raw material prices and to respond to fluctuations in the availability of different types of crude oil supplies. The Navajo Refinery converts approximately 90% of its raw materials throughput into high value light products. For 2003, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 57.9%, 23.2% and 8.6%, respectively, of the Navajo Refinery’s sales volumes.

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The following table sets forth certain information about the Navajo Refinery operations:

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
Crude charge (BPD)(1)
    56,080       57,650       53,640       57,830  
Refinery production (BPD)(2)
    63,680       66,380       59,390       63,230  
Sales of produced refined products (BPD)
    62,570       64,270       59,830       62,620  
Sales of refined products (BPD)(3)
    74,500       72,710       68,880       70,190  
Refinery utilization(4)
    93.5 %(5)     96.1 %     89.4 %(5)     96.4 %
Average per produced barrel(6)
                               
Net sales
  $ 38.95     $ 32.38     $ 31.02     $ 39.89  
Raw material costs
    31.52       26.66       24.46       30.17  
 
   
 
     
 
     
 
     
 
 
Refinery gross margin
    7.43       5.72       6.56       9.72  
Refinery operating expenses(7)
    3.24       2.70       2.84       2.92  
 
   
 
     
 
     
 
     
 
 
Net cash operating margin
  $ 4.19     $ 3.02     $ 3.72     $ 6.80  
 
   
 
     
 
     
 
     
 
 

  (1)   Crude charge represents the barrels per day of crude oil processed at the crude units at the 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 the refinery.
 
  (3)   Includes refined products purchased for resale representing 11,930 BPD, 8,440 BPD, 9,050 BPD, and 7,570 BPD, respectively.
 
  (4)   Crude charge divided by total crude capacity of 60,000 BPD through December 2003.
 
  (5)   Refinery utilization rate reflects the effects of turnarounds for major maintenance at the Navajo Refinery in 2003 and fiscal 2002.
 
  (6)   Represents average per barrel amounts for produced refined products sold. 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.
 
  (7)   Represents operating expenses of refinery, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

Navajo Refinery’s Artesia facility is located on a 400-acre site and has fully integrated crude distillation, fluid catalytic cracking (“FCC”), vacuum distillation, alkylation, hydrodesulfurization, isomerization, sulfur recovery and reforming units, and approximately 1.6 million barrels of feedstock and product tank storage, as well as other supporting units and office buildings at the site. In 2003, a gas oil hydrotreater and expansion was completed at the Navajo Refinery, described below under “Capital Improvement Projects.” 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 consists of a crude unit and an associated vacuum unit which were originally constructed after 1970, and approximately 1.0 million barrels of feedstock and product tank storage. The Lovington facility processes crude oil into intermediate products, which are transported to Artesia by means of two Company-owned pipeline, and which are then upgraded into finished products at the Artesia facility.

The Company has 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, 70 crude oil trucks and trailers, and over 600,000 barrels of related tankage.

The Company distributes refined products from the Navajo Refinery to its markets in Arizona, Albuquerque and west Texas primarily through two Company-owned pipelines that extend from Artesia to El Paso. In addition, the Company uses a leased pipeline to transport petroleum products to markets in central and northwest New Mexico.

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The Company has refined product storage at terminals in El Paso, Texas; Tucson, Arizona; and Albuquerque, Artesia, Moriarty and Bloomfield, New Mexico.

In 2000, the Company and a subsidiary of Koch Materials Company (“Koch”) formed a joint venture, NK Asphalt Partners, to manufacture and market asphalt and asphalt products in Arizona and New Mexico under the name “Koch Asphalt Solutions — Southwest.” The Company contributed its 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, the Company sold a 1% equity interest in NK Asphalt Partners to Koch thereby reducing the Company’s equity 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.

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. The Company’s products are shipped by Company-owned 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, Navajo Refinery began transporting petroleum products in late 1999 to 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, LPGs and carbon black oil) are currently shipped to El Paso on pipelines owned and operated by the Company. Of the products shipped to El Paso, most are subsequently shipped (either by the Company or by purchasers of the products from the Company) via common carrier pipelines to Tucson and Phoenix, Arizona. A smaller percentage of its 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. The Company expanded its capacity to supply El Paso in 1996 when the Company 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”), formerly Fina, Inc., to transport refined products from the Alon refinery in Big Spring, Texas to El Paso. Holly 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. The Company currently ships approximately 54,000 BPD into the El Paso market, 8,000 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 the Company’s 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 has a 1/3 interest) is currently 60,000 BPD. In August 2000, Valero announced that it is studying a potential expansion of this pipeline to 80,000 BPD. The Company believes 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 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 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 Shell Pipeline Company, LP (“Shell”), is linked to a 6-inch pipeline, also owned by Shell, and can transport to El Paso approximately 16,000 to 18,000 BPD of refined products produced on the Texas Gulf Coast

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(this capacity replaced a similar volume that had been produced in the Shell Oil Company refinery in Odessa, Texas, which was shut down in 1998). The Shell 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.

The Proposed Longhorn Pipeline

The proposed Longhorn Pipeline, which is owned by Longhorn Partners Pipeline, L.P. (“Longhorn Partners”), is an additional potential source of pipeline transportation from Gulf Coast refineries to El Paso. This pipeline is proposed to run approximately 700 miles from the Houston area of the Gulf Coast to El Paso, utilizing a direct route. Longhorn Partners has proposed to 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. Although most construction has been completed, the Longhorn Pipeline will not begin operations until the completion of certain agreed improvements and pre-start-up steps. Published reports indicate that construction in preparation for the start-up of the Longhorn Pipeline continued until late July 2002, when the construction activities were halted before completion of the project. 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 allows the Longhorn Pipeline to begin operations when agreed improvements have been completed. The plaintiffs in this proceeding are expected to file in the next few weeks a petition to the Supreme Court of the United States seeking review of the Court of Appeals decision. In January 2004, Longhorn officials stated they had received the additional financing needed to finalize the project and that they expect start-up to occur in the early summer of 2004.

If the Longhorn Pipeline operates as currently proposed, it could result in significant downward pressure on wholesale refined products prices and refined products margins in El Paso and related markets. However, any effects on the Company’s 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 Chevron-Texaco 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 53,000 BPD. According to their latest announcement, this expansion is expected to be completed during 2005. Although the Company’s results of operations could be adversely impacted by a start-up of the Longhorn Pipeline, the Company is unable to predict at this time the extent to which it could be negatively affected.

As a result of the Company’s settlement of litigation with Longhorn Partners, the Company in November 2002 prepaid $25,000,000 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 6 years from the date the Longhorn Pipeline begins operations if such operations begin by July 1, 2004. Under the agreement, the prepayment would cover shipments of 7,000 BPD by the Company for approximately 4 1/2 years assuming there were no curtailments of service once operations began. The Company intends to make use of the prepaid transportation services to ship purchased refined products on the Longhorn Pipeline to meet obligations of the Company to deliver refined products to customers in El Paso. The Company believes that these transportation services will be of benefit to the Company because most or all of such refined products shipped by the Company on the Longhorn Pipeline would take the place of Company products that can be profitably redirected to markets in northwest New Mexico and southern Colorado.

At the date of this report, it is not possible to predict whether and, if so, under what conditions, the Longhorn Pipeline will ultimately be operated, nor is it possible to predict the overall impact on the Company if the Longhorn Pipeline does not ultimately begin operations or begins operations at different possible future dates. Under the terms of the November 2002 settlement agreement that terminated litigation between the Company and Longhorn Partners, the Company would have an unsecured claim for repayment with interest of the Company’s $25,000,000 prepayment to Longhorn Partners for transportation services if the Longhorn Pipeline does not begin operations by July 1, 2004 or Longhorn Partners announces that it will not begin operations by that date.

Arizona and Albuquerque Markets

The Company currently ships approximately 33,000 BPD into, and accounts for approximately 14% of the refined products consumed in, the Arizona market, which is comprised primarily of Phoenix and Tucson. The Company currently ships approximately 11,000 BPD into, and accounts for approximately 15% of the refined products

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consumed, in the Albuquerque market. The common carrier pipelines used by the Company 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 the Company 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. No assurances can be given that the Company will not experience future constraints on its ability to deliver its products through the common carrier pipeline to Arizona. Any future constraints on the Company’s ability to transport its refined products to Arizona could, if sustained, adversely affect the Company’s 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 53,000 BPD. According to their latest announcement, this expansion is expected to be completed during 2005. For the Company, the proposed expansion would permit the shipment of 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 the Company cannot presently be estimated.

In the case of the Albuquerque market, the common carrier pipeline used by the Company to serve this market currently operates at or near capacity with resulting limitations on the amount of refined products that the Company and other shippers can deliver. The Company 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 the Company has an option to renew for an additional ten years. The Company owns and operates a 12” 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 in the last quarter of 1999. In December 2001, the Company completed its expansion of the Moriarty terminal and its pumping capacity on the Leased Pipeline. The terminal expansion included the addition of gasoline and jet fuel to the existing diesel fuel delivery capabilities, thus permitting the Company to provide a full slate of light products to the growing Albuquerque and Santa Fe, New Mexico areas. The enhanced pumping capabilities on the Company’s leased pipeline extending from the Artesia refinery through Moriarty to Bloomfield permits the Company to deliver a total of over 45,000 BPD of light products to these locations. If needed, additional pump stations could further increase the pipeline’s capabilities.

An additional factor that could affect some of the Company’s markets is excess pipeline capacity from the West Coast into the Company’s Arizona markets after the elimination of bottlenecks in 2000 on 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 could be shipped into the Company’s 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 the Company, and for export to other areas. The Company purchases crude oil from producers in nearby southeastern New Mexico and West Texas and from major oil companies. Crude oil is gathered both through the Company’s pipelines and tank trucks and through third party crude oil pipeline systems. In recent years the Company’s access to crude oil has expanded, primarily as a result of acquisitions in 1998 and 1999 of crude oil gathering, transportation and storage assets in West Texas. In March 2003, the Company sold its Iatan crude oil gathering system located in West Texas to Plains Marketing L.P. for a purchase price of $24 million in cash. In connection with the transaction, the Company and Plains have entered into a six and a half year agreement which commits the Company to transport such crude oil to the extent it purchases crude oil in the relevant area of the Iatan system at an agreed upon tariff. 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. The Company also purchases crude oil from producers and other petroleum companies in excess of the needs of its refineries for resale to other purchasers or users of crude oil. See Note 4 to the Consolidated Financial Statements in Item 8 of this report for additional information.

The Company also purchases isobutane, natural gasoline, and other feedstocks to supply the Navajo Refinery. In 2003, approximately 3,600 BPD of isobutane and 3,100 BPD of natural gasoline used in the Navajo Refinery’s

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operations were purchased from other oil companies in the region and shipped to the Artesia refining facilities on a Company-owned 65-mile pipeline running from Lovington to Artesia.

Principal Products and Customers

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

                                                                 
    Years ended December 31,
  Fiscal Years ended July 31,
    2003
  2002
  2002
  2001
    BPD
  %
  BPD
  %
  BPD
  %
  BPD
  %
Sales of produced refined products
                                                               
Gasolines
    36,210       57.9 %     37,650       58.6 %     34,820       58.2 %     36,000       57.5 %
Diesel fuels
    14,510       23.2 %     13,980       21.7 %     12,920       21.6 %     13,810       22.0 %
Jet fuels
    5,360       8.6 %     6,920       10.8 %     6,570       11.0 %     7,060       11.3 %
Asphalt
    4,380       7.0 %     3,480       5.4 %     3,450       5.7 %     3,480       5.6 %
LPG and other
    2,110       3.3 %     2,240       3.5 %     2,070       3.5 %     2,270       3.6 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Total
    62,570       100.0 %     64,270       100.0 %     59,830       100.0 %     62,620       100.0 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

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.

The Company’s principal customers for gasoline include other refiners, convenience store chains, independent marketers, an affiliate of PEMEX (the government-owned energy company of Mexico) and retailers. The Company’s 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. Under current standards, MTBE is a constituent of gasolines exported by the Company to northern Mexico and some grades of gasoline marketed in Phoenix during certain times of the year. Diesel fuel is sold to other refiners, truck stop chains, wholesalers, and railroads. Jet fuel is sold primarily for military use. 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. The Company sold approximately 5,800 BPD of jet fuel to the DESC in 2003. The Company has had a military jet fuel supply contract with the United States Government for each of the last 34 years. The Company’s size in terms of employees and refining capacity allows the Company to bid for military jet fuel sales contracts under a small business set-aside program. In August 2003, DESC awarded contracts to the Company for sales of military jet fuel for the period October 1, 2003 through September 30, 2004. The Company’s total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, was approximately 85 million gallons as compared to the total award for the 2002-2003 contract year of approximately 130 million gallons. Because of the pendency of the proposed merger with Frontier Oil Corporation at the time of the bidding for these contracts, the Company was not eligible for favorable small refiner status in the bidding process for the 2003-2004 contract year. Due to the Company’s ineligibility for small refiner status in this bidding process, the Company’s final bid prices were less and the volumes for which the Company was the successful bidder were smaller than in the case of military jet fuel contracts in prior years, when the Company was eligible for small refiner status. The Company estimates that the result of its ineligibility for small refiner status in the 2003-2004 contract year will be a reduction in pre-tax net income of approximately $1 to $2 million for the twelve months ending September 30, 2004. Since the formation of NK Asphalt Partners in July 2000, all asphalt from the Navajo Refinery is sold to NK Asphalt Partners. Carbon black oil is sold for further processing, and LPGs are sold to LPG wholesalers and LPG retailers.

Capital Improvement Projects

The Company has invested significant amounts in capital expenditures in recent years to expand and enhance the Navajo Refinery and expand its supply and distribution network. In December 2003, the Company completed a major expansion project at the Navajo Refinery that included the construction of a new gas oil hydrotreater unit and the expansion of the crude refining capacity from 60,000 BPD to 75,000 BPD. The total cost of the project was approximately $85 million, excluding capitalized interest.

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The hydrotreater enhances higher value light product yields and expands the Company’s ability to produce additional quantities of gasolines meeting the present California Air Resources Board (“CARB”) standards, which were adopted in the Company’s Phoenix market for winter months beginning in late 2000, and enables the Company to meet the recently adopted EPA nationwide low-sulfur gasoline requirements that became effective in 2004 for all of the Company’s gasolines. Additionally, in fiscal 2001 the Company 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, the Company 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 BPD to 75,000 BPD. The permits received by the Company to date for the Artesia facility, subject to possible minor modifications, should also permit a second phase expansion of the Navajo Refinery’s crude oil capacity to an estimated 80,000 BPD, but a schedule for such additional expansion has not been determined.

For the 2004 year, the Company’s capital budget for the Navajo Refinery totals $7 million for various refining and pipeline improvement projects. Additionally, $17 million was approved in the 2004 capital budget for management to pursue new high-return pipeline transportation and terminal opportunities relating to the distribution network of the Navajo Refinery.

The Company’s Leased Pipeline is an 8” pipeline running for more than 300 miles from Chaves County to San Juan County, New Mexico. The Company owns and operates a 59 mile, 12” pipeline from the Navajo Refinery to the Leased Pipeline and also owns 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 during the last quarter of calendar 1999. In December 2001, the Company completed an expansion of the Moriarty terminal and the pumping capacity on the Leased Pipeline. The terminal expansion included the addition of gasoline and jet fuel to the existing diesel fuel delivery capabilities, thus permitting the Company to provide a full slate of light products to the growing Albuquerque and Santa Fe, New Mexico areas. The enhanced pumping capabilities on the Leased Pipeline extending from the Artesia refinery through Moriarty to Bloomfield will permit the Company to deliver a total of over 45,000 BPD of light products to these locations. If needed, additional pump stations could further increase the pipeline’s capabilities.

Woods Cross Refinery

On June 1, 2003, the Company acquired from ConocoPhillips the Woods Cross Refinery located near Salt Lake City, Utah and related assets, including a refined products terminal in Spokane, WA, a 50% ownership interest in refined products terminals in Boise and Burley, Idaho, and 25 retail service stations located in Utah and Wyoming for an agreed price of $25 million plus inventory less obligations assumed. The total cash purchase price, including expenses and the deposit made in 2002, was $58.3 million. For the purchase price, the Company 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, the Company sold the retail assets for $7 million (excluding inventory proceeds), resulting in a pre-tax loss of approximately $400,000, due principally to transaction expenses.

The Woods Cross Refinery is being operated by Holly Refining & Marketing Company, a wholly owned subsidiary of the Company. The Woods Cross refinery has a crude oil capacity of 25,000 BPD and processes primarily sweet crude oils into high value light products. For the period from June 1, 2003 to December 31, 2003, the Woods Cross Refinery processed approximately 22,500 BPD of crude oil.

The Woods Cross Refinery currently obtains its supply of crude oil primarily from suppliers in Canada, Wyoming, Utah and Colorado via common carrier pipeline, which runs from the Canadian border through Wyoming to the refinery. Its primary markets include Utah, Idaho and Wyoming where it distributes its products largely through a network of Phillips 66 branded marketers. The purchase of the Woods Cross Refinery also included certain pipelines

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and other transportation assets used in connection with the refinery, and a 10-year exclusive license to market fuels under the Phillips brand in the states of Utah, Wyoming, Idaho and Montana.

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 the truck rack at the refinery. Remaining volumes are shipped via pipelines owned by ChevronTexaco Corporation to numerous terminals, including the Company’s terminals at Boise and Burley, Idaho and Spokane, Washington. The Woods Cross Refinery is one of five refineries located in Utah. The Company estimates 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.

The Company is finalizing its clean fuels strategy for the Woods Cross Refinery which will be required to address mandated lower sulfur in on-road diesel fuel on June 1, 2006. The facility is currently meeting the applicable new low-sulfur gasoline requirements that commenced in 2004. The current 2004 capital budget for the Woods Cross Refinery includes preliminary costs of $13.5 million for increased hydrogen production and $3 million associated with the selected low-sulfur diesel desulfurization project. The 2004 capital budget totals $19.5 million, which includes the above projects and an additional amount of approximately $3 million for other refinery improvements.

The following table sets forth certain information about the Woods Cross Refinery operations since its acquisition by the Company:

         
    Seven Months
    Ended
    December 31,
    2003
Crude charge(BPD)(1)
    22,540  
Refinery production (BPD)(2)
    23,870  
Sales of produced refined products (BPD)
    22,480  
Sales of refined products (BPD)(3)
    22,680  
Refinery utilization(4)(5)
    90.2 %
Average per produced barrel(6)
       
Net sales
  $ 40.91  
Raw material costs
    34.81  
 
   
 
 
Refinery gross margin
    6.10  
Refinery operating expenses(7)
    3.92  
 
   
 
 
Net cash operating margin
  $ 2.18  
 
   
 
 

(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at the 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 the refinery.
 
(3)   Includes refined products purchased for resale representing 200 BPD.
 
(4)   Crude charge divided by total crude capacity of 25,000 BPD from acquisition date of June 1, 2003.
 
(5)   Refinery utilization rate reflects the effects of a turnaround for major maintenance in 2003.
 
(6)   Represents average per barrel amounts for produced refined products sold. 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.
 
(7)   Represents operating expenses of refinery, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product terminals.

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Set forth below is certain information regarding the principal products produced at the Woods Cross Refinery since the Company’s acquisition on June 1, 2003.

                 
    Seven Months
    Ended December 31,
    2003
    BPD
  %
Sales of produced refined products
               
Gasolines
    13,980       62.2 %
Diesel fuels
    5,960       26.5 %
Jet fuels
    600       2.7 %
LPG and other
    1,940       8.6 %
 
   
 
     
 
 
Total
    22,480       100.0 %
 
   
 
     
 
 

Montana Refinery

The Company’s 7,000 BPD petroleum refinery in Great Falls, Montana processes a wide range of crude oils and primarily serves markets in Montana. For the last two years, the Montana Refinery has operated at an average annual crude capacity utilization rate of approximately 96%.

The following table sets forth certain information about the Montana Refinery operations:

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
Crude charge (BPD) (1)
    6,740       6,650       6,560       6,170  
Refinery production (BPD) (2)
    7,350       7,220       6,970       6,410  
Sales of produced refined products (BPD)
    7,150       6,940       7,230       6,460  
Sales of refined products (BPD) (3)
    7,620       7,470       7,540       6,810  
Refinery utilization (4)
    96.3 %     95.0 %     93.7 %     88.1 %
Average per produced barrel (5)
               
Net sales
  $ 35.80     $ 30.65     $ 30.38     $ 36.83  
Raw material costs
    28.17       23.79       22.23       26.22  
 
   
 
     
 
     
 
     
 
 
Refinery gross margin
    7.63       6.86       8.15       10.61  
Refinery operating expenses (6)
    5.85       5.67       5.55       5.84  
 
   
 
     
 
     
 
     
 
 
Net cash operating margin
  $ 1.78     $ 1.19     $ 2.60     $ 4.77  
 
   
 
     
 
     
 
     
 
 

(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at the 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 the refinery.
 
(3)   Includes refined products purchased for resale representing 470 BPD, 530 BPD, 310 BPD and 350 BPD, respectively.
 
(4)   Crude charge divided by total crude capacity of 7,000 BPD.
 
(5)   Represents average per barrel amounts for produced refined products sold. 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 refinery, exclusive of depreciation, depletion, and amortization.

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. The Company competes principally with three other

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Montana refineries. The Montana Refinery is currently meeting the applicable new low sulfur gasoline requirements that commences in 2004. The Company does not anticipate significant required expenditures at the facility for the 2006 low sulfur diesel requirements.

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

                                                                 
    Years ended December 31,
  Fiscal Years ended July 31,
    2003
  2002
  2002
  2001
    BPD
  %
  BPD
  %
  BPD
  %
  BPD
  %
Sales of produced refined products
                                                               
Gasolines
    2,880       40.3 %     3,010       43.4 %     2,920       40.4 %     2,740       42.4 %
Diesel fuels
    1,050       14.7 %     1,090       15.7 %     1,130       15.6 %     1,290       20.0 %
Jet fuels
    510       7.1 %     530       7.6 %     520       7.2 %     380       5.8 %
Asphalt
    2,380       33.3 %     2,010       29.0 %     2,370       32.8 %     1,780       27.6 %
LPG and other
    330       4.6 %     300       4.3 %     290       4.0 %     270       4.2 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Total
    7,150       100.0 %     6,940       100.0 %     7,230       100.0 %     6,460       100.0 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

For the 2004 year, the capital budget for the Montana Refinery totals $500,000, most of which is for various refinery improvements.

PIPELINE TRANSPORTATION OPERATIONS

Pipeline Transportation Business

In recent years, the Company has developed a pipeline transportation business generating revenues from unaffiliated parties. The pipeline transportation operations currently include approximately 500 miles of the 2,000 miles of pipeline that the Company owns and operates, of which approximately 200 miles are also part of the supply and distribution network of the Navajo Refinery. Additionally, the Company has a 70% investment in Rio Grande Pipeline Company as described below. For 2004, the Company did not budget any significant amount for capital expenditures that would be used for the pipeline transportation business.

The Company has a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), a pipeline joint venture with BP p.l.c. to transport liquid petroleum gases to Mexico. Deliveries by the joint venture began in April 1997. On June 30, 2003, the Company purchased from The Williams Companies, Inc. its 45% interest in Rio Grande for a purchase price of $28.7 million, less cash recorded in consolidation of the joint venture of $7.3 million, increasing the Company’s ownership in the Rio Grande Company from 25% to 70%.

In 1998, the Company 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 the Company’s 12” pipeline between Orla and El Paso, Texas pursuant to a long-term lease of certain capacity of the Company’s 12” pipeline. In August 1998, FINA began transporting to El Paso gasoline and diesel fuel from its Big Spring, Texas refinery, and the Company began to realize pipeline rental and terminalling revenues from FINA under these agreements. In August 2000, Alon USA LP, 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, the Company acquired certain pipeline transportation and storage assets located in West Texas and New Mexico in an asset exchange with ARCO Pipeline Company. The acquired assets, including 100 miles of pipelines and over 250,000 barrels of tankage, allow the Company to transport crude oil for unaffiliated companies and increase the Company’s ability to access additional crude oil for the Navajo Refinery.

In March 2003, the Company sold its Iatan crude oil gathering system located in West Texas to Plains Marketing L.P. for a purchase price of $24 million in cash. In connection with the transaction, the Company and Plains have entered into a six-and-a-half-year agreement that commits the Company to transport any crude oil purchased by the

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Company in the relevant area of the Iatan system at an agreed upon tariff. The sale resulted in a pre-tax gain of $16.2 million.

ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices

The Company leases its principal corporate offices in Dallas, Texas. The Company’s lease for its principal corporate offices expires April 30, 2006, requires lease payments of $40,000 per month plus certain operating expenses, and provides no option to renew. The operations of Holly Corporation, the parent company, are performed at this location. Functions performed by the parent company include overall corporate management, refinery management, planning and strategy, legal support, accounting support, treasury management and tax reporting.

Exploration and Production

The Company conducts a small-scale oil and gas exploration and production program. For 2004, the Company has budgeted approximately $300,000 for capital expenditures related to oil and gas exploration activities.

Jet Fuel Terminal

The Company owns and operates a 120,000-barrel-capacity jet fuel terminal near Mountain Home, Idaho, which serves as a terminalling facility for jet fuel sold by unaffiliated producers to the Mountain Home United States Air Force Base.

Other Investments

The Company has a 49% interest in MRC Hi-Noon LLC, a joint venture operating retail service stations and convenience stores in Montana and accounts for its share of earnings from the joint venture using the equity method. The Company has reserved approximately $800,000 related to the collectability of advances to the joint venture and related accrued interest.

Employees and Labor Relations

As of March 1, 2004, the Company had approximately 735 employees, of which approximately 302 are covered by collective bargaining agreements that will expire during 2006. The Company considers its 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 the Company’s 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 the Company and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures by the Company. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on the Company’s operations, results of operations and capital requirements. The Company believes that its current operations are in substantial compliance with existing environmental laws, regulations and permits.

The Company’s operations and many of the products it manufactures 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 the Company’s 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, following discussions initiated by the Company, the Company entered into a Consent Decree (the “Consent Decree”) with the Environmental Protection Agency (“EPA”), the New Mexico Environment Department and the Montana Department of Environmental Quality with respect to a global settlement of issues concerning the application of air quality requirements to past and future operations of the Company’s refineries. The Consent Decree was entered by the federal court in New Mexico in March 2002 and requires investments by the Company

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expected to total approximately $15 million over a period expected to end in 2009, of which approximately $8 million has been expended, as well as changes in operational practices at the Navajo and Montana refineries. See the discussion of the Consent Decree below and under Item 3, “Legal Proceedings.”

The CAA may authorize the EPA to require modifications in the formulation of the refined transportation fuel products the Company manufactures 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 require the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners, such as the Company, and for refiners serving those Western states exhibiting lesser air quality problems and for small business refiners, such as the Company.

The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts per million. The current standard is 500 parts-per-million. As a small business refiner, the Company may, on a refinery-by-refinery basis, choose to comply with the 2006 program and extend its interim gasoline standard by three years (until 2011) or delay the diesel standard by four years (until 2010) and keep its original gasoline sulfur program timing.

The EPA has recently stated its intent to propose new regulations that will limit emissions from diesel fuel powered engines used in non-road activities such as mining, construction, agriculture, railroad and marine. The EPA has also stated its intent to simultaneously limit the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. The EPA proposed the new non-road diesel engine emissions and related fuel sulfur standards early in 2003. Promulgation of the final rule is expected during the second quarter of 2004.

Additionally, effective January 1, 1995, certain cities in the United States were required to use only reformulated gasoline (“RFG”), a cleaner burning fuel. Phoenix is the only principal market of the Company that currently requires the equivalent of RFG (or an alternative clean burning gasoline formula), although this requirement could be implemented in other markets over time. Phoenix adopted the even more rigorous California Air Resources Board (“CARB”) fuel specifications for winter months beginning in late 2000. This new requirement, the recently adopted low-sulfur gasoline and diesel requirements described above, and other requirements of the CAA could cause the Company to expend substantial amounts to permit the Company’s refineries to produce products that meet newly applicable requirements. The Company believes that the completion of the hydrotreater project described above under “Capital Improvement Projects” allows the Company to meet current 2004 gasoline standards and has substantially enhanced the Company’s ability to meet future standards.

The Company is aware of public concern regarding possible groundwater contamination resulting from the use of MTBE (methyl tertiary butyl ether) 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.

The Company’s 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.

The Company generates 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.

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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 the Company’s historical operations, as well as in the Company’s current ordinary operations, the Company has 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, the Company faces 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 the Company manufactured, handled, used, released or disposed of.

The Company is and has been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries, including the Consent Decree discussed above. Current and future 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.

The Company’s operations are also subject to various laws and regulations relating to occupational health and safety. The Company maintains safety, training and maintenance programs as part of its 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.

The Company 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 the Company’s 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 operations of the Company and could require substantial expenditures by the Company for the installation and operation of systems and equipment not currently possessed by the Company.

Insurance

The Company’s operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. The Company maintains various insurance coverages, including business interruption insurance, subject to certain deductibles. The Company is not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in the judgment of the Company, do not justify such expenditures. Shortly after the events of September 11, 2001, the Company completed a security assessment of its principal facilities. Several security measures identified in the assessment have been implemented. Because of recent changes in insurance markets, insurance coverages available to the Company have become more costly in recent years and in some cases less available. So long as this current trend continues, the Company expects to incur higher insurance costs and anticipates that, in some cases, it may be necessary to reduce somewhat the extent of insurance coverages because of reduced insurance availability at acceptable premium costs.

Cost Reduction and Production Efficiency Program

In May 2000, the Company announced a cost reduction and production efficiency program. The cost reduction and production efficiency program included productivity enhancements and a reduction in workforce. Implementation of the program and other initiatives have achieved approximately $20 million in annual pre-tax improvements. As part of the implementation of cost reductions, the Company offered a voluntary early retirement program to eligible employees, under which 55 employees retired by December 31, 2001. The pre-tax cost of the voluntary early retirement program was $6.8 million and was reflected in the Company’s earnings for the fiscal year ended July 31, 2000.

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Item 3. Legal Proceedings

On August 20, 2003, Frontier Oil Corporation (“Frontier”) filed a lawsuit in the Delaware Court of Chancery seeking declaratory relief and damages based on allegations that the Company repudiated its obligations and breached an implied covenant of good faith and fair dealing under an agreement (the “Frontier Merger Agreement”) announced in late March 2003 under which Frontier and the Company were to be combined. On August 21, 2003, the Company formally notified Frontier of the Company’s 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 Frontier 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, the Company filed in the Delaware Court of Chancery its Answer and Counterclaims seeking declaratory judgments that the Company had not repudiated the Frontier Merger Agreement, that Frontier had repudiated the Frontier Merger Agreement, that Frontier had breached certain representations made by Frontier in the Frontier Merger Agreement, that the Company’s obligations under the Frontier Merger Agreement were and are excused and that the Company may terminate the Frontier Merger Agreement without liability, and seeking damages as well as costs and attorneys’ fees. To the date of this report, the Company has not taken any actions, beyond the sending of the August 21, 2003 notification with respect to the Beverly Hills High School matter, under the various provisions of the Frontier Merger Agreement relating to the Company’s rights to terminate the Frontier Merger Agreement. Frontier was permitted by the court to amend its Complaint shortly before the beginning of the trial to assert that the Company’s actions entitle Frontier to payment of a breakup fee of $16 million plus certain legal expenses. The trial with respect to Frontier’s amended Complaint and the Company’s Answer and Counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. Following submission of post-trial briefs and oral argument, a decision is expected to be announced within several months after completion of the trial. Although it is not possible at the date of this report to predict the outcome of this litigation, the Company believes that the claims made by Frontier in the litigation are wholly without merit and that the Company’s counterclaims are well founded.

The Company has pending in the United States Court of Federal Claims a lawsuit against the Department of Defense relating to claims totaling approximately $298 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 the Company’s motion for partial summary judgment on most of the issues raised by the Company. The ruling on the motions for summary judgment in the Company’s case does not constitute a final ruling for the Company as to the Company’s claims but instead the judge’s ruling is expected to be followed by substantial discovery proceedings and then a trial on factual issues. The Company plans to seek to amend its complaint in this lawsuit to add an additional claim for approximately $900,000 which was submitted to the Government in September 2003 and denied in November 2003. The Company’s lawsuit may be significantly affected by interlocutory appeals allowed in February 2004 by the United States Court of Appeals for the Federal Circuit (the “Federal Circuit Appeals Court”) with respect to rulings by two United States Court of Federal Claims judges in cases relating to military fuel sales of two other refining companies. The rulings in these two 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. A decision by the Federal Circuit Appeals Court in these cases is expected to be issued near the end of 2004 and such decision could substantially affect the Company’s lawsuit. It is not possible at the date of this report to predict the outcome of further proceedings in the Company’s case or the impact on the Company’s case of a decision by the Federal Circuit Appeals Court in the related cases, nor is it possible to predict what amount, if any, will ultimately be payable to the Company with respect to the Company’s lawsuit.

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Petitions for review are pending before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit Appeals Court”) with respect to rulings by the FERC in proceedings brought by the Company and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. The Company is 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 are the subject of proceedings in the D.C. Circuit Appeals Court resulted in reparations payments to the Company in 2003 totaling approximately $15.3 million relating principally to the period from 1993 through July 2000. The D.C. Circuit Appeals Court heard oral argument in November 2003 on issues relating to reparations to the Company and other shippers. As of the date of this report, the D.C. Circuit Appeals Court has not issued an opinion in the case. The opinion of the D.C. Circuit Court of Appeals could result in a determination that the reparations actually due to the Company in this matter are less than or more than the $15.3 million received by the Company in 2003. In the event that as a result of these proceedings the actual reparations amount due to the Company is determined to be less than the amounts received by the Company in 2003, part or all of the amounts received by the Company would have to be refunded. Although it is not possible at the date of this report to predict the outcome of the pending proceedings on this matter in the D.C. Circuit Appeals Court, the Company believes that any amount of reparations payments which may be required to be refunded as a result of these proceedings would not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

In December 2003, the Company and the EPA agreed to settle issues relating to flaring incidents in 2002 and 2003 at the Artesia, New Mexico refinery. The flaring incidents were reported by the Company to the EPA pursuant to the terms of the Consent Decree approved and entered by the United States District Court for the District of New Mexico in March 2002 concerning the application of federal and state air quality requirements to the Company’s New Mexico and Montana refineries. Under the settlement the Company will pay a $45,000 penalty and make additional environmentally beneficial expenditures of not less than $45,000 for a project to be approved by the EPA.

As a result of a computer system problem at the Artesia loading rack at the Navajo Refinery, for almost 12 months during 2001 and 2002 the Company inadvertently issued delivery documents to exchange partners that failed to properly contain statements required by federal regulations that the product does not meet the requirements for reformulated gasoline. The Company believes 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. The Company discovered and corrected the problem during its annual attestation process in May 2002 and self-reported the violation in its annual attestation statement made to the EPA on May 24, 2002. In February 2004, after an informal inquiry concerning this matter among others, the EPA notified the Company that it would receive an information request letter pursuant to Clean Air Act Section 114, which the Company has not received as of the date of this annual report. The Company has no indication at this stage whether or not the EPA will consider this a matter for enforcement action. If such enforcement action were taken, the Company does not believe that it would result in a material adverse effect on the Company’s results of operations or financial condition.

The Company is a party to various other litigation and proceedings which the Company believes, based on advice of counsel, will not have a materially adverse impact on the Company’s 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 the Company’s 2003 year.

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PART II

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

The Company’s common stock is 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 for the periods indicated:

                                 
                            Total
Years ended December 31,
  High
  Low
  Dividends
  Volume
2002
                               
First Quarter
  $ 20.80     $ 16.15     $ 0.10       2,912,400  
Second Quarter
  $ 19.40     $ 14.25     $ 0.11       2,722,800  
Third Quarter
  $ 17.87     $ 15.25     $ 0.11       1,996,500  
Fourth Quarter
  $ 23.09     $ 14.57     $ 0.11       1,961,400  
2003
                               
First Quarter
  $ 28.80     $ 19.90     $ 0.11       3,410,200  
Second Quarter
  $ 30.02     $ 27.05     $ 0.11       4,148,200  
Third Quarter
  $ 28.50     $ 24.20     $ 0.11       5,310,400  
Fourth Quarter
  $ 27.70     $ 24.18     $ 0.11       2,148,600  

As of March 1, 2004, the Company had approximately 1,400 stockholders of record.

The Company intends 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, the financial condition of the Company and other factors. The Senior Notes and Credit Agreement limit the payment of dividends. See Note 10 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 the Company’s definitive proxy statement for the annual meeting of stockholders to be held on May 13, 2004.

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Item 6. Selected Financial Data

The following table shows selected financial information for the Company 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 the consolidated financial statements of the Company and related notes thereto included elsewhere in this Form 10-K.

                                                         
                    Five Months    
                    Ended    
    Years Ended December 31,
  December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2002
  2001
  2000
  1999
            (Unaudited)   (In thousands, except per share data)                
FINANCIAL DATA
                                                       
For the year
                                                       
Sales and other revenues
  $ 1,403,244     $ 973,689     $ 448,637     $ 888,906     $ 1,142,130     $ 965,946     $ 597,986  
Income before income taxes
  $ 74,359     $ 28,984     $ 8,517     $ 50,896     $ 121,895     $ 18,634     $ 33,159  
Income tax provision
  28,306     10,159     3,114     18,867     48,445     7,189     13,222  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Net income
  $ 46,053     $ 18,825     $ 5,403     $ 32,029     $ 73,450     $ 11,445     $ 19,937  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Net income per common share — basic
  $ 2.97     $ 1.21     $ 0.35     $ 2.06     $ 4.84     $ 0.71     $ 1.21  
Net income per common share — diluted
  $ 2.88     $ 1.18     $ 0.34     $ 2.01     $ 4.77     $ 0.71     $ 1.21  
Cash dividends declared per common share
  $ 0.44     $ 0.44     $ 0.11     $ 0.41     $ 0.37     $ 0.34     $ 0.32  
Average number of common shares outstanding:
                                                       
Basic
  15,505     15,557     15,516     15,560     15,187     16,131     16,507  
Diluted
  16,016     15,924     15,902     15,971     15,387     16,131     16,507  
Net cash provided by (used for) operating activities
  $ 70,756     $ 27,323     $ (8,733 )   $ 42,301     $ 106,770     $ 46,804     $ 47,628  
Net cash used for investing activities
  $ (119,146 )   $ (41,967 )   $ (24,769 )   $ (21,953 )   $ (28,752 )   $ (20,143 )   $ (23,979 )
Net cash provided by (used for) financing activities
  $ 35,814     $ (17,723 )   $ (13,862 )   $ (14,558 )   $ (15,806 )   $ (27,227 )   $ (22,057 )
At end of year
                                                       
Working capital
  $ (28,261 )   $ 12,445     $ 12,445     $ 59,873     $ 57,731     $ 363     $ 13,851  
Total assets
  $ 708,892     $ 515,793     $ 515,793     $ 502,306     $ 490,429     $ 464,362     $ 390,982  
Total debt, including current maturities and borrowings under the credit agreement
  $ 67,142     $ 25,714     $ 25,714     $ 34,285     $ 42,857     $ 56,595     $ 70,341  
Stockholders’ equity
  $ 268,609     $ 228,494     $ 228,494     $ 228,556     $ 201,734     $ 129,581     $ 128,880  

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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.

OVERVIEW

The Company is 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. The Company’s profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. The Company also operates a pipeline transportation business consisting of leased and owned pipelines and the Company’s 70% investment in the Rio Grande Pipeline Company.

The Company’s 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. The Company’s sales and other revenues for 2003 were $1.4 billion and the Company’s net income for 2003 was $46.1 million. The Company’s sales and other revenues and its net income for 2003 increased from $974 million and $18.8 million, respectively, for its year ended December 31, 2002. The Company’s principal expenses are costs of products sold and operating expenses. The Company’s total operating costs and expenses for 2003 were $1.36 billion, increased from $947 million for the year ended December 31, 2002.

The following important events or activities occurred in 2003 with respect to the Company’s business:

    On July 30, 2003, the Company changed its fiscal year-end from July 31 to December 31. In connection with this change and in accordance with SEC rules, on September 12, 2003, the Company filed a transition report for the five-month period ended December 31, 2002, which includes a comparison of the five months ended December 31, 2002 to the five months ended December 31, 2001. The following discussion covers the calendar years ended December 31, 2003 and 2002, and the fiscal years ended July 31, 2002 and 2001.
 
    On March 4, 2003, the Company sold its 400-mile Iatan crude oil gathering system located in west Texas to Plains All-American Pipeline, L.P. for $24 million in cash, and agreed to transport crude oil purchased in West Texas on the Iatan system at an agreed upon tariff for six and a half years. The Iatan system, while profitable, was not considered central to the Company’s refining operations. The sale resulted in a pre-tax gain to the Company of $16.2 million. The proceeds from the sale increased the Company’s cash resources available for investment in its core refining operations, including its acquisition of the Woods Cross Refinery.
 
    On June 1, 2003, the Company acquired from ConocoPhillips the Woods Cross Refinery located near Salt Lake City, Utah and related assets, including a refined products terminal in Spokane, WA, a 50% ownership interest in refined products terminals in Boise and Burley, Idaho, and 25 retail service stations located in Utah and Wyoming for an agreed price of $25 million plus inventory less obligations assumed. The total cash purchase price, including expenses and the deposit made in 2002, was $58.3 million. In accounting for the purchase, the Company 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. The purchase was financed from working capital, proceeds from the Iatan sale, and borrowings under the Company’s credit facility. In connection with the acquisition, the credit facility was increased in 2003 to $100 million. In August 2003, the Company sold the retail service station assets for $7 million (excluding inventory proceeds), resulting in a pre-tax loss of approximately $400,000, due principally to transaction expenses.
 
    On June 30, 2003, the Company purchased from The Williams Companies, Inc. its 45% interest in Rio Grande Pipeline Company for a purchase price of $28.7 million, less cash of $7.3 million recorded by the Company upon the inclusion of the Rio Grande Pipeline Company in the Company’s consolidated financial statements. This purchase increased the Company’s ownership in the Rio Grande Pipeline Company to

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      70%. Effective June 30, 2003, the Company changed its method of accounting for its interest in the Rio Grande Pipeline Company from the equity method to full consolidation with minority interest.

    The Company is involved in litigation with Frontier Oil Corporation relating to the agreement of the two companies to merge entered into on March 30, 2003. Each corporation has asserted claims against the other for damages. The trial with respect to this litigation began in a Delaware court on February 23, 2004 and was completed on March 5, 2004 and a decision is expected within several months after the completion of the trial. Through December 31, 2003, the Company had spent approximately $6.9 million in legal fees and other expenses with respect to this litigation.
 
    In April 2003 and June 2003, the Company received reparation payments totaling approximately $15.3 million from SFPP. The payments were for claims brought by the Company before the Federal Energy Regulatory Commission (“FERC”) relating to tariffs of common carrier pipelines owned and operated by SFPP for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The final decision of the FERC is subject to judicial review. The D.C. Circuit Appeals Court heard oral argument in November 2003 on issues relating to reparations to the Company and other shippers. As of the date of this report, the D.C. Circuit Appeals Court has not issued an opinion in the case. In the event that as a result of these proceedings the actual reparations amount due to the Company is determined to be less than the amounts received by the Company in 2003, part or all of the amounts received by the Company would have to be refunded. Although it is not possible at the date of this report to predict the outcome of the pending proceedings on this matter in the D.C. Circuit Appeals Court, the Company believes that any amount of reparations payments which may be required to be refunded as a result of these proceedings would not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.
 
    In 2003, the Company completed the two most significant capital projects in its history. Together these two projects, both at its Navajo Refinery, cost approximately $85 million, excluding capitalized interest. The hydrotreater project, completed in July 2003, enhances higher value light product yields and expands the Company’s ability to produce additional quantities of gasolines meeting the present California Air Resources Board (“CARB”) standards, which have been adopted in the Company’s Phoenix market for winter months beginning in late 2000, and to meet the recently adopted EPA nationwide low-sulfur gasoline requirements which became effective in 2004. Contemporaneous with the hydrotreater project, the Company expanded the Navajo Refinery’s crude oil refining capacity from 60,000 BPD to 75,000 BPD. The expansion was completed in December 2003.

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RESULTS OF OPERATIONS

Financial Data

Information at December 31, 2003 and 2002, July 31, 2002 and 2001 and for the years ended December 31, 2003, July 31, 2002 and 2001 is derived from the Company’s audited financial statements. The reported numbers for the year ended December 31, 2002, which have not been audited, are derived from the books and records of the Company and in the opinion of management reflect all adjustments necessary to present the financial position and results of operations in accordance with generally accepted accounting principles.

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
            (In thousands, except per share data)        
Sales and other revenues
  $ 1,403,244     $ 973,689     $ 888,906     $ 1,142,130  
Operating costs and expenses
                               
Cost of products sold (exclusive of depreciation, depletion, and amortization)
    1,155,858       796,946       698,245       871,321  
Operating expenses (exclusive of depreciation, depletion, and amortization)
    131,045       97,799       96,289       100,410  
Selling, general and administrative expenses (exclusive of depreciation, depletion, and amortization)
    34,782       22,029       22,248       23,123  
Depreciation, depletion and amortization
    36,275       28,550       27,699       27,327  
Exploration expenses, including dry holes
    1,031       1,315       1,379       2,042  
 
   
 
     
 
     
 
     
 
 
Total operating costs and expenses
    1,358,991       946,639       845,860       1,024,223  
 
   
 
     
 
     
 
     
 
 
Gain on sale of assets
    15,814                    
 
   
 
     
 
     
 
     
 
 
Income from operations
    60,067       27,050       43,046       117,907  
 
                               
Other income (expense)
                               
Equity in earnings of joint ventures
    1,398       3,442       7,753       5,302  
Minority interest in income of joint venture
    (758 )                  
Interest expense, net
    (1,678 )     (1,508 )     (1,425 )     (2,467 )
Reparations payment received
    15,330                    
Other income
                1,522       1,153  
 
   
 
     
 
     
 
     
 
 
 
    14,292       1,934       7,850       3,988  
 
   
 
     
 
     
 
     
 
 
Income before income taxes
    74,359       28,984       50,896       121,895  
Income tax provision
    28,306       10,159       18,867       48,445  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 46,053     $ 18,825     $ 32,029     $ 73,450  
 
   
 
     
 
     
 
     
 
 
Net income per common share — basic
  $ 2.97     $ 1.21     $ 2.06     $ 4.84  
Net income per common share — diluted
  $ 2.88     $ 1.18     $ 2.01     $ 4.77  

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Financial Data (continued)

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
            (In thousands)        
Cash and cash equivalents
  $ 11,690     $ 24,266     $ 71,630     $ 65,840  
Working capital
  $ (28,261 )   $ 12,445     $ 59,873     $ 57,731  
Total assets
  $ 708,892     $ 515,793     $ 502,306     $ 490,429  
Total debt, including current maturities and borrowing under the revolving credit agreement
  $ 67,142     $ 25,714     $ 34,285     $ 42,857  
Stockholders’ equity
  $ 268,609     $ 228,494     $ 228,556     $ 201,734  
Total debt to capitalization ratio(1)
    20.0 %     10.1 %     13.0 %     17.5 %
Sales and other revenues(2)
                               
Refining
  $ 1,373,406     $ 953,308     $ 868,730     $ 1,120,248  
Pipeline Transportation
    21,030       19,078       18,588       18,454  
Corporate and Other
    8,808       1,303       1,588       3,428  
 
   
 
     
 
     
 
     
 
 
Consolidated
  $ 1,403,244     $ 973,689     $ 888,906     $ 1,142,130  
 
   
 
     
 
     
 
     
 
 
Income (loss) from operations(2)
                               
Refining
  $ 53,854     $ 26,726     $ 42,725     $ 116,218  
Pipeline Transportation
    29,110       11,294       10,621       10,243  
Corporate and Other
    (22,897 )     (10,970 )     (10,300 )     (8,554 )
 
   
 
     
 
     
 
     
 
 
Consolidated
  $ 60,067     $ 27,050     $ 43,046     $ 117,907  
 
   
 
     
 
     
 
     
 
 
Net cash provided by (used for) operating activities
  $ 70,756     $ (27,323 )   $ 42,301     $ 106,770  
Net cash used for investing activities
  $ (119,146 )   $ (41,967 )   $ (21,953 )   $ (28,752 )
Net cash provided by (used for) financing activities
  $ 35,814     $ (17,723 )   $ (14,558 )   $ (15,806 )
Capital expenditures
  $ 74,642     $ 47,701     $ 35,313     $ 28,571  
EBITDA(3)
  $ 112,312     $ 59,042     $ 80,020     $ 151,689  

(1) 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.

(2) The Company has two major business segments: Refining and Pipeline Transportation. The Refining segment involves the refining of crude oil and wholesale marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes the Company’s Navajo Refinery, Woods Cross Refinery and Montana Refinery. The Woods Cross Refinery was acquired in June 2003. The petroleum products produced by the Refining segment are marketed in the southwestern United States, Utah, Wyoming, Montana and northern Mexico. Certain pipelines and terminals operate in conjunction with the Refining segment as part of the supply and distribution networks of the refineries. The Refining segment also includes the equity earnings from the Company’s 49% (50% prior to January 1, 2002) interest in NK Asphalt Partners, which manufactures and markets asphalt and asphalt products in Arizona and New Mexico. The pipeline transportation segment currently includes approximately 500 miles of the Company’s pipeline assets in Texas and New Mexico. Revenues from the Pipeline Transportation segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations. Pipeline Transportation segment revenues do not include any amount relating to pipeline transportation services provided for the Company’s refining operations. The Pipeline Transportation segment also includes the earnings from the Company’s 70% (25% prior to June 30, 2003) interest in Rio Grande Pipeline Company, which provides petroleum products transportation. Operations of the Company that are not included in the two reportable segments are included in Corporate and other, which includes costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses and interest charges, as well as a small-scale oil and gas exploration and production program and a small

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equity investment in retail gasoline stations and convenience stores. Additionally included in Corporate and other during 2003 were the retail stations purchased from ConocoPhillips as part of the Woods Cross Refinery acquisition that were subsequently sold.

(3) Earnings before interest, taxes, depreciation and amortization - 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 based upon generally accepted accounting principles: however, the amounts included in the EBITDA calculation are derived from amounts included in the consolidated financial statements of the Company. EBITDA should not be considered as an alternative to net income or operating income, as an indication of operating performance of the Company 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 enhances an investor’s understanding of the Company’s ability to satisfy principal and interest obligations with respect to the Company’s indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used by Company 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.

Operating Data — Refining Operations

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
Crude charge (BPD)(1)
    76,040       64,300       60,200       64,020  
Refinery production (BPD)(2)
    85,030       73,600       66,360       69,640  
Sales of produced refined products (BPD)
    82,900       71,210       67,060       69,080  
Sales of refined products (BPD)(3)
    95,420       80,180       76,420       77,000  
Refinery utilization(4)
    93.2 %(5)     96.0 %     89.9 %(5)     95.6 %
Average per produced barrel(6)
                               
Net sales
  $ 38.99     $ 32.22     $ 30.95     $ 39.60  
Raw material costs
    31.76       26.38       24.22       29.80  
     
     
     
     
 
Refinery gross margin
    7.23       5.84       6.73       9.80  
Refinery operating expenses(7)
    3.58       2.99       3.13       3.19  
     
     
     
     
 
Net cash operating margin
  $ 3.65     $ 2.85     $ 3.60     $ 6.61  
     
     
     
     
 

(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at the Company’s 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 the Company’s refineries.
 
(3)   Includes refined products purchased for resale representing 12,520 BPD, 8,970 BPD, 9,360 BPD, and 7,920 BPD, respectively.
 
(4)   Crude charge divided by total crude capacity of 67,000 BPD through May 2003, and 92,000 BPD through December 2003 which reflects the acquisition of the Woods Cross Refinery in June 2003.
 
(5)   Refinery utilization rate reflects turnarounds for major maintenance at the Navajo Refinery and Woods Cross Refinery in 2003 and the Navajo Refinery in fiscal 2002.
 
(6)   Represents average per barrel amounts for produced refined products sold. 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.
 
(7)   Represents operating expenses of refinery, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

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Results of Operations — Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Summary

For the year ended December 31, 2003, net income was $46.1 million ($2.88 per diluted share) compared to $18.8 million ($1.18 per diluted share) for the year ended December 31, 2002. The increase in net income was primarily due to: higher refining margins in 2003 as compared to 2002, seven months of operations of the Woods Cross Refinery which was acquired from ConocoPhillips on June 1, 2003, a $16.2 million pre-tax gain realized upon the sale of certain pipeline assets and a $15.3 million reparation payment received from Kinder Morgan Energy Partners, L.P. These positive factors were offset to a certain extent by $2.1 million of costs incurred in connection with the proposed merger with Frontier Oil Corporation (“Frontier”) and $6.9 million of legal costs associated with the litigation with Frontier through the end of 2003.

Sales and Other Revenues, Cost of Products Sold and Gross Refinery Margins

Sales and other revenues increased 44% from $973.7 million in 2002 to $1,403.2 million in 2003 due primarily to the addition of the operations of the Woods Cross Refinery in June 2003 and higher refined product sales prices. The average sales price per barrel sold increased 21% from $32.54 in 2002 to $39.41 in 2003. Cost of products sold increased 45% from $796.9 million in 2002 to $1,155.9 million in 2003 due primarily to the addition of the operations of the Woods Cross Refinery and higher costs of purchased crude oil. The average price paid per barrel of crude oil purchased increased 20% from $26.38 in 2002 to $31.76 in 2003.

The gross refining margin per produced barrel was $7.23 in 2003 as compared to $5.84 in 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, costs of crude oil purchased and operating costs.

Operating Expenses

Operating expenses increased 34% from $97.8 million in 2002 to $131.0 million in 2003 due primarily to the addition of the operations of the Woods Cross Refinery and, to a lesser extent, higher refinery utility costs of $6.8 million.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased 58% from $22.0 million in 2002 to $34.8 million in 2003 due primarily to $6.9 million of legal costs associated with the litigation with Frontier through the end of 2003, $2.1 million of costs incurred in connection with the proposed merger with Frontier, and the addition of the operations of the Woods Cross Refinery.

Depreciation

Depreciation expense increased 27% from $28.6 million in 2002 to $36.3 million in 2003 due to the acquisition of the Woods Cross Refinery and the large capital projects completed at the Navajo Refinery.

Equity in Earnings of Joint Ventures

Equity in earnings of joint ventures in 2003 included $0.5 million for the Company’s 25% interest in the Rio Grande joint venture during the first six months of 2003 and $1.0 million for the Company’s 49% interest in the NK Asphalt Joint Venture. Since the acquisition of an additional 45% interest in the Rio Grande joint venture on June 30, 2003, the Company has included its 70% interest in the Rio Grande joint venture in its consolidated financial statements. In 2002, equity in earnings of joint ventures included $1.7 million for the Rio Grande joint venture and $1.9 million for the NK Asphalt joint venture. The $0.9 million reduction in contribution from the NK Asphalt joint venture during 2003 was primarily due to lower margins for asphalt.

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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.

Reparations Payment Received

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

Income Taxes

Income taxes increased by 177% from $10.2 million in 2002 to $28.3 million in 2003 due primarily to a $45.4 million increase in net income before income taxes and, to a lesser extent, an increase in the effective tax rate from 35.1% to 38.1%. The lower effective rate in 2002 was due to state tax refunds received and net operating loss benefits recognized. The large deferred tax expense in 2003 as compared to 2002 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 Year Ended July 31, 2001

Summary

For the fiscal year ended July 31, 2002, net income was $32.0 million ($2.01 per diluted share) compared to $73.5 million ($4.77 per diluted share) for the fiscal year ended July 31, 2001. During the fiscal year ended July 31, 2002, the Company along with the refining industry as a whole, experienced substantially lower refining margins than prevailed in the prior fiscal year.

Sales and Other Revenues, Cost of Products Sold and Gross Refinery Margins

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 barrel sold decreased 22% from $39.82 in fiscal 2001 to $31.11 in fiscal 2002, due primarily to lower refined product sales prices. 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.

The gross refinery margin per barrel was $6.73 in fiscal 2002 as compared to $9.80 for fiscal 2001. 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, costs of crude oil purchased and operating data.

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 3% 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 asphalt joint venture.

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Interest Expense and Interest Income

Interest expense declined $2 million during fiscal 2002 from fiscal 2001 primarily due to reduced interest costs as the Company made required principal payments on long-term debt. The reduction in interest expense was partially offset by a $1 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash and cash equivalents decreased by $12.6 million during the year ended December 31, 2003. The cash flow generated from operations of $70.8 million plus the cash provided by financing activities of $35.8 million was less than the cash used for investing activities of $119.1 million. Working capital declined during the year ended December 31, 2003 by $41 million due to borrowings of $50 million under the Company’s Revolving Credit Agreement in connection with the Company’s expansion and acquisition activities discussed below.

In May 2003, the Company amended its Revolving Credit Agreement with a group of banks led by Canadian Imperial Bank of Commerce and increased the commitment from $75 million to $100 million. The Company now has access to $100 million of commitments that can be used for revolving credit loans and letters of credit. Previously the Company had access to $75 million of commitments of which only $37.5 million could be used for revolving credit loans. At December 31, 2003, the Company had letters of credit outstanding under the facility of $4.2 million and had $50 million borrowings outstanding. The Credit Agreement expires October 2004 and therefore the borrowings under the agreement at December 31, 2003 are classified as a current liability. The Company plans to extend the Credit Agreement during the second quarter of 2004.

On October 30, 2001, the Company announced plans to repurchase up to $20 million of the Company’s common stock. Such repurchases have been made from time to time in open market purchases or privately negotiated transactions, subject to price and availability. The repurchases have been financed with available corporate funds. During the year ended December 31, 2003, the Company repurchased 43,000 shares at a cost of approximately $894,000 or an average of $20.79 per share. From inception of the plan through December 31, 2003, the Company has repurchased 272,400 shares at a cost of approximately $4.7 million. No stock repurchases have been made since February 7, 2003.

The Company believes its internally generated cash flow together with its Credit Agreement, as expected to be extended, provide sufficient resources to fund planned capital projects, scheduled repayments of the Senior Notes, continued payment of dividends (although dividend payments must be authorized by the Board of Directors and cannot be guaranteed) and the Company’s liquidity needs for the foreseeable future.

Cash Flows from Operating Activities

Net cash provided by operating activities amounted to $70.8 million in 2003, compared to $27.3 million in 2002. Comparing 2003 to 2002, the $43.4 million increase in cash provided by operations was primarily the result of a $11.4 million increase in net income (excluding the effect of the pre-tax gain on sale of assets), a $7.7 million increase in depreciation expense, an increase of $17.7 million in deferred taxes and a reduction of $25.0 million in prepaid transportation paid to Longhorn Partners in 2002. These increases were partially offset by items decreasing cash flow, including an increase in turnaround expenditures of $25.2 million, and increases in inventories of $14.5 million and income taxes receivable of $6.7 million, when comparing 2003 to 2002. Additionally, as a result of the Woods Cross Refinery acquisition, accounts receivable, inventories and accounts payable increased in 2003.

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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 for Investing Activities and Capital Projects

Cash flows used for investing activities were $119.1 million for 2003, as compared to $42.0 million for 2002. Cash expenditures for property, plant and equipment were $74.6 million and $47.7 million in 2003 and 2002, respectively. Most of the increase in 2003 is due to the Navajo Refinery’s hydrotreater and expansion projects. The Company spent $55.8 million in 2003 (plus a $2.5 million deposit made in 2002) to acquire the Woods Cross Refinery, retail assets and inventories. In accounting for the purchase, the Company 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. The Company spent $28.7 million in 2003 for the purchase of an additional 45% interest in the Rio Grande Pipeline Company. Effective with this purchase the Company consolidates the results of the Rio Grande Pipeline Company and reflects 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 the Company’s acquisition of the additional partnership interest. In addition to cash, at the acquisition date, the Rio Grande Pipeline Company owned current assets of $.6 million, net property, plant and equipment of $34.9 million, other net assets of $7.8 million, and current liabilities of $.4 million. Additionally in 2003, the Company spent $3.3 million for investments in the asphalt joint venture. The Company’s net cash flow used for investing activities was reduced in 2003 by a $4.9 million distribution to the Company from the asphalt joint venture, by $24 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. During 2002, the Company’s net cash flow used by investing activities was reduced by a $2.5 million distribution to the Company from the Rio Grande joint venture, an $8.5 million distribution to the Company from the asphalt joint venture and by $460,000 in proceeds from the sale of a 1% interest in the asphalt joint venture, offset by $3.3 million in investments in the asphalt joint venture.

Cash flows used for investing activities were $22.0 million in fiscal 2002 and $28.8 million in fiscal 2001. Cash expenditures for property, plant and equipment were $35.3 million and $28.6 million respectively. Also in fiscal 2002, the Company spent $3.3 million for investment in the asphalt joint venture, offset by a $3.2 million distribution to the Company from the Rio Grande joint venture, an $8.5 million distribution to the Company from the asphalt joint venture, $460,000 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. In fiscal 2001, the Company spent $5.9 million for investment in the joint venture and received a $5.6 million distribution from the asphalt joint venture and a $100,000 distribution from the Rio Grande joint venture.

Construction at the Navajo Refinery of the hydrotreator project was completed in July 2003 and the expansion project was completed in December 2003. The hydrotreater enhances higher value light product yields and expands the Company’s ability to produce additional quantities of gasolines meeting the present California Air Resources Board (“CARB”) standards, which have been adopted in the Company’s Phoenix market for winter months beginning in late 2000, and to meet the recently adopted EPA nationwide low-sulfur gasoline requirements that became effective in 2004. Contemporaneous with the hydrotreater project, the Navajo Refinery has been expanded resulting in an increase in crude oil refining capacity from 60,000 BPD to approximately 75,000 BPD. The expansion was completed in December 2003. The hydrotreater and expansion projects cost approximately $85 million, which was higher than the Company’s original estimate of approximately $56 million due to the increased costs and scope of certain refinery infrastructure upgrades, added refining capacity and sulfur recovery capabilities, and increased actual costs of previously estimated portions of the projects. The permits received by Navajo to date for the Artesia facility, subject to possible minor modifications, should also permit a second phase expansion of Navajo’s crude oil capacity from an estimated 75,000 BPD to an estimated 80,000 BPD, but a schedule for such additional expansion has not been determined.

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Planned Capital Expenditures

The Company’s capital budget adopted for 2004 totals approximately $45 million, comprised of $7 million for refining and pipeline transportation improvement projects for the Navajo Refinery, $19.5 million for projects at the Woods Cross Refinery, $.5 million for projects at the Montana Refinery, $.3 million for oil and gas exploration and production, $.7 million for information technology and other, and $17 million for management to pursue new high-return pipeline transportation and terminal opportunities relating to the distribution network of the Navajo Refinery. For 2004, the Company expects to expend approximately $32 million on capital projects, which amount includes certain carryover of capital projects approved in previous years, less carryover into 2005 of certain of the 2004 approved capital items, including the $17 million to pursue pipeline and terminal projects for which no material amounts are expected to be expended in 2004. The Company is finalizing its clean fuels strategy for the Woods Cross Refinery which will be required to address mandated lower sulfur in on-road diesel fuel on June 1, 2006. The facility is currently meeting the applicable new low-sulfur gasoline requirements that commenced in 2004. The current 2004 capital budget for the Woods Cross Refinery includes preliminary costs of $13.5 million for increased hydrogen production and $3 million associated with the selected low-sulfur diesel desulfurization project, and approximately $3 million for other refinery improvements.

Cash Flows for Financing Activities

Cash flows provided by financing activities amounted to $35.8 million in 2003, as compared to cash flows of $17.7 million used for financing activities in 2002. In 2003, the Company borrowed $50 million under its 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 borrowing plus the $369,000 received upon the exercise of stock options in 2003 were partially offset by an $8.6 million scheduled repayment of long-term debt, $900,000 spent to repurchase shares of common stock and $5.1 million of dividends paid. In 2002, the Company made an $8.6 million scheduled repayment of long-term debt, purchased $3.7 million of treasury stock, and paid $6.7 million in dividends, offset partially by $1.8 million received upon the exercise of options.

Cash flows used for financing activities amounted to $14.6 million in fiscal 2002, compared to $15.8 million in fiscal 2001. During fiscal 2002, the Company repaid $8.6 million of its 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. The Company had no bank borrowings during the 2002 fiscal year. During fiscal 2001, the Company repaid $13.7 million of its fixed rate term debt, received proceeds of $4.4 million for common stock issued upon exercise of stock options and paid $5.6 million in dividends.

Contractual Obligations and Commitments

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

                                         
    Payments Due by Period
            Less than            
Contractual Obligations
  Total
  1 Year
  2-3 Years
  4-5 Years
  Over 5 Years
    (In thousands)
Long-term debt (stated maturities)
  $ 17,142     $ 8,571     $ 8,571     $     $  
Operating leases
  $ 20,581     $ 6,072     $ 11,502     $ 2,820     $ 187  

In July 2000, the Company and a subsidiary of Koch Materials Company (“Koch”) formed a joint venture, NK Asphalt Partners, to manufacture and market asphalt and asphalt products in Arizona and New Mexico under the name “Koch Asphalt Solutions — Southwest.” The Company contributed its 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, the Company sold a 1%

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equity interest to Koch, thereby reducing the Company’s 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. The Company is required to make additional contributions to the joint venture of up to $3,250,000 for each of the next seven years contingent on the earnings level of the joint venture. The Company expects to finance such contributions from its share of cash flows of the joint venture. In the event that the Company fails to make the required contributions, the Company may lose its voting rights during such default and the other partner could cause the partnership to bring a proceeding to collect the unpaid contributions plus interest at the prime rate plus 2%.

As part of the Consent Decree filed December 2001 implementing an agreement reached among the Company, the Environmental Protection Agency, the New Mexico Environment Department, and the Montana Department of Environmental Quality, the Company is required to make investments at the Company’s New Mexico and Montana refineries for the installation of certain state of the art pollution control equipment currently expected to total approximately $15 million over a period expected to end in 2009, of which approximately $8 million has been expended.

CRITICAL ACCOUNTING POLICIES

The Company’s discussion and analysis of its financial condition and results of operations are based upon the Company’s 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 the Company 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. The Company considers the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact its 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

The Company’s 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 prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2003, the Company’s LIFO inventory layers were valued at historical costs that were established in years when price levels were much lower; therefore, the Company’s results of operation are less sensitive to current market price reductions. As of December 31, 2003, the excess of current cost over the LIFO inventory value of the Company’s crude oil and refined product inventories was approximately $39.9 million.

Deferred Maintenance Costs

The Company’s 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, the Company for turnarounds utilizes contract labor as well as its 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. The Company records the costs of turnarounds as deferred charges and then amortizes the deferred costs over the expected periods of benefit. The American Institute of Certified Public Accountants has issued an Exposure Draft for a Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment”, which would require the Company to expense turnaround costs as they are incurred. If this proposed statement had been adopted in its current form as of December 31, 2003, the Company would have been required to expense $24.7 million of deferred maintenance costs and would be required to expense all future turnaround costs as incurred.

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Long-lived Assets

The Company calculates depreciation and amortization based on estimated useful lives and salvage values of its assets. When assets are placed into service, the Company makes estimates with respect to their useful lives that the Company believes are reasonable. However, factors such as competition, regulation or environmental matters could cause the Company to change its estimates, thus impacting the future calculation of depreciation and amortization. The Company evaluates 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, 2003, and 2002, or the fiscal years ended July 31, 2002 and 2001.

Contingencies

The Company is subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. The Company is 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.

Prepaid Transportation Costs

As a result of the Company’s settlement of litigation with Longhorn Partners, the Company in November 2002 prepaid $25,000,000 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 6 years from the date the Longhorn Pipeline begins operations if such operations begin by July 1, 2004. Under the agreement, the prepayment would cover shipments of 7,000 BPD by the Company for approximately 4 1/2 years assuming there were no curtailments of service once operations began. The Company plans to make use of the prepaid transportation services to ship purchased refined products on the Longhorn Pipeline and will amortize the prepaid costs as refined products are shipped. Under the terms of the November 2002 settlement agreement that terminated litigation between the Company and Longhorn Partners, the Company would have an unsecured claim for repayment with interest of the Company’s $25,000,000 prepayment to Longhorn Partners for transportation services in the event the Longhorn Pipeline did not begin operations by July 1, 2004 or announced that it would not begin operations by that date. At the date of this report, it is not possible to predict whether and, if so, under what conditions, the Longhorn Pipeline will ultimately be operated, nor is it possible to predict the overall impact on the Company if the Longhorn Pipeline does not ultimately begin operations or begins operations at different possible future dates. If it becomes probable that the Longhorn Pipeline will not become operational or if there is indication of impairment in the value of the prepaid transportation costs, the Company would record an impairment loss equal to the amount by which the carrying value exceeds the fair value.

New Accounting Pronouncements

SFAS No. 142 “Goodwill and Other Intangible Assets”

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” which changes how goodwill and other intangible assets are accounted for subsequent to their initial recognition. The Company adopted the standard effective August 1, 2002 and there was no effect on its financial condition, results of operations, or cash flows.

SFAS No. 143 “Accounting for Asset Retirement Obligations”

In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” which requires that the fair value for an asset retirement obligation be capitalized as part of the carrying amount of the long-lived asset if a reasonable estimate of fair value can be made. SFAS No. 143 was effective for fiscal years beginning after June 15, 2002. The Company adopted the standard effective August 1, 2002 and there was no material effect on its financial condition, results of operations, or cash flows.

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SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”

In August 2001, FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. This statement supersedes SFAS No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of”, but carries over the key guidance from SFAS No. 121 in establishing the framework for the recognition and measurement of long-lived assets to be disposed of by sale and addresses significant implementation issues. SFAS No. 144 was effective for fiscal years beginning after December 15, 2001. The Company adopted the standard effective August 1, 2002 and there was no effect on its financial condition, results of operations, or cash flows.

SFAS No. 146 “Accounting for Certain Costs Associated with Exit or Disposal Activities”

In June 2002, FASB issued SFAS No. 146 “Accounting for Certain Costs Associated with Exit or Disposal Activities” which nullifies Emerging Issues Task Force (“EITF”) 94-3 and requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and establishes fair value as the objective for initial measurement of liabilities. This differs from EITF 94-3 which stated that liabilities for exit costs were to be recognized as of the date of an entity’s commitment to an exit plan. SFAS No. 146 was effective for exit or disposal activities that are initiated after December 31, 2002. The Company adopted the standard on January 1, 2003, and there was no effect on its financial condition, results of operations, or cash flows.

SFAS No. 148 “Accounting for Stock-Based Compensation—Transition and Disclosure”

In December 2002, FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation—Transition and Disclosure,” an amendment of SFAS No. 123. This statement provides alternative methods of transition to SFAS No. 123’s fair value method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148’s amendment of the disclosure requirements was effective for interim periods beginning after December 15, 2002. SFAS No. 148’s amendment of the transition and annual disclosure requirements of SFAS No. 123 was effective for fiscal years ending after December 15, 2002. See Note 3 to the Consolidated Financial Statements for effect of this standard on the Company’s financial condition, results of operations, and cash flows.

Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others”

In January 2003, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The Company adopted the standard on January 1, 2003 and there was no material effect on its financial condition, results of operations, or cash flows.

Interpretation No. 46, “Consolidation of Variable Interest Entities”

In January 2003 (revised December 2003), the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity and if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of FIN 46 apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim period beginning after June 15, 2003. The Company is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of FIN 46 by the Company on December 31, 2003 had no material effect on the Company’s financial condition, results of operations, or cash flows.

SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement will result in a more complete depiction of an entity’s liabilities and equity and will thereby assist investors and creditors in assessing the amount, timing, and likelihood of potential future cash outflows and equity share issuances. This statement is effective for

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financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. It is to be implemented by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of the statement and still existing at the beginning of the interim period of adoption. Restatement is not permitted. The Company adopted the standard on July 1, 2003, and there was no effect on its financial condition, results of operations, or cash flows.

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.” These revisions require 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 statement now requires interim period disclosures regarding net periodic pension cost and employer contributions. The statement is effective for fiscal years ending after December 15, 2003. The Company adopted the standard on December 31, 2003.

Exposure Draft for a Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment”

The American Institute of Certified Public Accountants has issued an Exposure Draft for a Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment,” which would require major maintenance activities to be expensed as costs are incurred. As of December 31, 2003, the Company had approximately $24.7 million of deferred maintenance costs, all relating to refinery turnarounds in prior periods, which are being amortized over various benefit periods. The current monthly amortization is $737,000. If this proposed Statement of Position had been adopted in its current form, as of December 31, 2003, the Company would have been required to expense $24.7 million of deferred maintenance costs and would be required to expense all future turnaround costs as incurred.

ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS

Many factors outside of the Company’s control affect the prices and demand for its products, including seasonal and weather-related factors and governmental regulations and policies.

The Company’s operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond the Company’s 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 the Company’s activities. Operating results can be affected by these industry factors, by competition in the particular geographic areas that the Company serves and by factors that are specific to the Company, such as the success of particular marketing programs and the efficiency of the Company’s refinery operations.

In addition, the Company’s 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 the control of the Company. 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 the Company’s earnings and cash flows.

The Company is 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

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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 the Company’s access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict the Company’s access to funds for capital expenditures.

The potential operation of new refined product transportation pipelines or proration of existing pipelines could impact the supply of refined products to the Company’s existing markets, such as El Paso, Albuquerque and Phoenix.

The proposed Longhorn Pipeline, which is owned by Longhorn Partners Pipeline, L.P. (“Longhorn Partners”), is an additional potential source of pipeline transportation from Gulf Coast refineries to El Paso. This pipeline is proposed to run approximately 700 miles from the Houston area of the Gulf Coast to El Paso, utilizing a direct route. Longhorn Partners has proposed to 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. Although most construction has been completed, the Longhorn Pipeline will not begin operations until the completion of certain agreed improvements and pre-start-up steps. Published reports indicate that construction in preparation for start-up of the Longhorn Pipeline continued until late July 2002, when the construction activities were halted before completion of the project. 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 allows the Longhorn Pipeline to begin operations when agreed improvements have been completed. The plaintiffs in this proceeding are expected to file in the next few weeks a petition to the Supreme Court of the United States seeking review of the Court of Appeals decision. In January 2004, Longhorn officials stated they had received the additional financing needed to finalize the project and that they expect start-up to occur in the early summer of 2004.

If the Longhorn Pipeline operates as currently proposed, it could result in significant downward pressure on wholesale refined products prices and refined products margins in El Paso and related markets. However, any effects on the Company’s 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 Chevron-Texaco has not announced any plans to expand their common carrier pipeline from El Paso to Albuquerque to address their capacity constraint, Kinder Morgan’s SFPP, L.P. (“SFPP”) has announced plans to expand the capacity of its pipeline from El Paso to the Arizona market by 53,000 BPD. According to their latest announcement, this expansion is expected to be completed during 2005. Although the Company’s results of operations could be adversely impacted by the start-up of the Longhorn Pipeline, the Company is unable to predict at this time the extent to which it could be negatively affected.

As a result of the Company’s settlement of litigation with Longhorn Partners, the Company in November 2002 prepaid $25,000,000 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 6 years from the date the Longhorn Pipeline begins operations if such operations begin by July 1, 2004. Under the agreement, the prepayment would cover shipments of 7,000 BPD by the Company for approximately 4 1/2 years assuming there were no curtailments of service once operations began. The Company plans to make use of the prepaid transportation services to ship purchased refined products on the Longhorn Pipeline to meet obligations of the Company to deliver refined products to customers in El Paso. The Company believes that these transportation services will be of benefit to the Company because most or all of such refined products shipped by the Company on the Longhorn Pipeline would take the place of Company products that can be profitably redirected to markets in northwest New Mexico and southern Colorado.

At the date of this report, it is not possible to predict whether and, if so, under what conditions, the Longhorn Pipeline will ultimately be operated, nor is it possible to predict the overall impact on the Company if the Longhorn Pipeline does not ultimately begin operations or begins operations at different possible future dates. Under the terms of the November 2002 settlement agreement that terminated litigation between the Company and Longhorn Partners, the Company would have an unsecured claim for repayment with interest of the Company’s $25,000,000 prepayment to Longhorn Partners for transportation services in the event the Longhorn Pipeline did not begin operations by July 1, 2004 or announced that it would not begin operations by that date.

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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 Shell Pipeline Company, LP (“Shell”), is linked to a 6-inch pipeline, also owned by Shell, and can transport to El Paso approximately 16,000 to 18,000 BPD of refined products produced on the Texas Gulf Coast (this capacity replaced a similar volume that had been produced in the Shell Oil Company refinery in Odessa, Texas, which was shut down in 1998). The Shell 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 the Company’s markets is excess pipeline capacity from the West Coast into the Company’s 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 the Company’s 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 projects, if consummated, could result in further increases in the supply of products to the Company’s markets.

In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in the Company’s geographic market. These transactions could increase the future competitive pressures on the Company.

The common carrier pipelines used by the Company 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 the Company 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 the Company will not experience future constraints on its ability to deliver its products through the common carrier pipeline to Arizona. Any future constraints on the Company’s ability to transport its refined products to Arizona could, if sustained, adversely affect the Company’s 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 53,000 BPD. According to their latest announcement, this expansion is expected to be completed during 2005. For the Company, the proposed expansion would permit the shipment of 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 the Company cannot presently be estimated.

In the case of the Albuquerque market, the common carrier pipeline used by the Company to serve this market currently operates at or near capacity with resulting limitations on the amount of refined products that the Company and other shippers can deliver. The Company leases 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”). The Company operates a 12” 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, the Company completed its 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 the Company to provide a full slate of light products to the growing Albuquerque and Santa Fe, New Mexico area. The enhanced pumping capabilities on the Company’s leased pipeline extending from the Artesia refinery through Moriarty to Bloomfield

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will permit the Company to deliver a total of over 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 the Company’s ability to transport its refined products to Arizona or Albuquerque could, if sustained, adversely affect the Company’s results of operations and financial condition.

The Company did not benefit from treatment as a “small refiner” in bidding for its current contracts for delivery of military jet fuel to the United States government.

In August 2003, the Defense Energy Support Center (“DESC”), a part of the United States Department of Defense, awarded contracts to the Company for sales of military jet fuel for the period October 1, 2003 through September 30, 2004. The Company’s total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, was approximately 85 million gallons as compared to the total award for the 2002-2003 contract year of approximately 130 million gallons. Because of the pendency of the proposed merger with Frontier Oil Corporation at the time of the bidding for these contracts, the Company was not eligible for favorable small refiner status in the bidding process. In consequence of the Company’s ineligibility for small refiner status in this bidding process for the 2003-2004 contract year, the Company’s final bid prices were less and the volumes for which the Company was the successful bidder were smaller than in the case of military jet fuel contracts in prior years, when the Company was eligible for small refiner status. The Company estimates that the result of its ineligibility for small refiner status in the 2003-2004 contract year will be a reduction in pre-tax income of approximately $1 to $2 million for the twelve months ending September 30, 2004.

A lawsuit is pending with respect to the Company’s proposed merger with Frontier Oil Corporation.

On August 20, 2003, Frontier Oil Corporation (“Frontier”) filed a lawsuit in the Delaware Court of Chancery seeking declaratory relief and damages based on allegations that the Company repudiated its obligations and breached an implied covenant of good faith and fair dealing under an agreement (the “Frontier Merger Agreement”) announced in late March 2003 under which Frontier and the Company were to be combined. On August 21, 2003, the Company formally notified Frontier of the Company’s 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 Frontier 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, the Company filed in the Delaware Court of Chancery its Answer and Counterclaims seeking declaratory judgments that the Company had not repudiated the Frontier Merger Agreement, that Frontier had repudiated the Frontier Merger Agreement, that Frontier had breached certain representations made by Frontier in the Frontier Merger Agreement, that the Company’s obligations under the Frontier Merger Agreement were and are excused and that the Company may terminate the Frontier Merger Agreement without liability, and seeking damages as well as costs and attorneys’ fees. To the date of this report, the Company has not taken any actions, beyond the sending of the August 21, 2003 notification with respect to the Beverly Hills High School matter, under the various provisions of the Frontier Merger Agreement relating to the Company’s rights to terminate the Frontier Merger Agreement. Frontier was permitted by the court to amend its Complaint shortly before the beginning of the trial to assert that the Company’s actions entitle Frontier to payment of a breakup fee of $16 million plus certain legal expenses. The trial with respect to Frontier’s amended Complaint and the Company’s Answer and Counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. Following submission of post-trial briefs and oral argument, a decision is expected to be announced within several months after completion of the trial. Although it is not possible at the date of this report to predict the outcome of this litigation, the Company believes that the claims made by Frontier in the litigation are wholly without merit and that the Company’s counterclaims are well founded.

An appeal is pending with respect to the Company’s lawsuit to recover amounts in dispute in connection with the Company’s prior sales of military jet fuel to the United States government.

The Company has pending in the United States Court of Federal Claims a lawsuit against the Department of Defense relating to claims totaling approximately $298 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 the

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Company’s motion for partial summary judgment on most of the issues raised by the Company. The ruling on the motions for summary judgment in the Company’s case does not constitute a final ruling for the Company as to the Company’s claims but instead the judge’s ruling is expected to be followed by substantial discovery proceedings and then a trial on factual issues. The Company plans to seek to amend its complaint in this lawsuit to add an additional claim for approximately $900,000 which was submitted to the Government in September 2003 and denied in November 2003. The Company’s lawsuit may be significantly affected by interlocutory appeals allowed in February 2004 by the United States Court of Appeals for the Federal Circuit (the “Federal Circuit Appeals Court”) with respect to rulings by two United States Court of Federal Claims judges in cases relating to jet fuel sales of two other refining companies. The rulings in these two 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. A decision by the Federal Circuit Appeals Court in these cases is expected to be issued near the end of 2004 and such decision could substantially affect the Company’s lawsuit. It is not possible at the date of this report to predict the outcome of further proceedings in the Company’s case or the impact on the Company’s case of the decision by the Federal Circuit Appeals Court in the related cases, nor is it possible to predict what amount, if any, will ultimately be payable to the Company with respect to the Company’s lawsuit.

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

New governmental requirements, such as requirements for the use of only reformulated gasoline in certain markets, could require the Company to make substantial capital expenditures in order to produce the required products.

Effective January 1, 1995, certain cities in the country were required to use only reformulated gasoline (“RFG”), a cleaner burning fuel. Phoenix is the only principal market of the Company that currently requires the equivalent of RFG (or an alternative clean burning gasoline formula), although this requirement could be implemented in other markets over time. Phoenix adopted the even more rigorous California Air Resources Board (“CARB”) fuel specifications for winter months beginning in late 2000. Completion of the hydrotreater project, described above under “Cash Flows for Investing Activities and Capital Projects,” has enhanced higher value light product yields and expanded the Company’s ability to produce more gasoline which meets the present CARB standards in the Company’s Phoenix market and meets the EPA Low-Sulfur Gasoline requirements that become effective in 2004. The EPA has required the use of ultra-low sulfur highway diesel fuel effective June 1, 2006 and is proposing requirements for non-road diesel. The Company is in the process of beginning engineering activities for projects to meet these requirements. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations could cause the Company to expend substantial amounts to permit the Company’s refineries to produce products that meet applicable requirements.

RISK MANAGEMENT

The Company uses certain strategies to reduce some commodity price and operational risks. The Company does not attempt to eliminate all market risk exposures when the Company believes the exposure relating to such risk would not be significant to the Company’s future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit.

The Company’s 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 the Company’s earnings, financial condition and cash flows.

The Company periodically utilizes petroleum commodity futures contracts to reduce its exposure to the price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. The Company has also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. The Company regularly utilizes 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. The Company believes 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

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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, the Company 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 the Company from the risk that the refined product margins with respect to the hedged gasoline sales would decline. 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 $161,000 for the year ended July 31, 2001, which was included in cost of products sold.

During the fiscal year ended July 31, 2001, the Company 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, the Company 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, the Company 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 the Company from the risk that the refinery margin would decline with respect to the hedged crude oil and refined products. To effect the hedges the Company 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, the Company marked the value of the outstanding hedges to fair value in accordance with SFAS No. 133 and included $47,000 of income in comprehensive income. In March 2003, as the forecasted transactions occurred, the Company reclassified $108,000 of actual losses from comprehensive income to cost of sales. The ineffective portion of the hedges resulted in a $32,000 gain that was also included in cost of sales.

In October 2003, the Company 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 $71,000 and were recorded into refining operating costs. At December 31, 2003, included in comprehensive income, was a gain of $599,000, 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.

At December 31, 2003, the Company had outstanding unsecured debt of $17.1 million and had $50 million of borrowings outstanding under its Credit Agreement. The Company does not have significant exposure to changing interest rates on its unsecured debt because the interest rates are fixed, the average maturity is approximately one year and such debt represents less than 10% of the Company’s total capitalization. As the interest rates on the Company’s 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. There were no bank borrowings during fiscal 2002 or fiscal 2001. Additionally, the Company invests 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 is low. A ten percent change in the market interest rate over the next year would not materially impact the Company’s earnings or cash flow since the interest rates on the Company’s long-term debt are fixed and the Company’s borrowings under the Credit Agreement, if any, and cash investments are at short-term market rates and such interest has historically not been significant as compared to the total operations of the Company. A ten percent change in the market interest rate over the next year would not materially impact the Company’s financial condition since the average maturity of the Company’s long-term debt is approximately one year, such debt represents less than 10% of the Company’s total capitalization, and the Company’s borrowings under the Credit Agreement and cash investments are at short-term market rates.

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The Company’s operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. The Company maintains various insurance coverages, including business interruption insurance, subject to certain deductibles. The Company is not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in the judgment of the Company, do not justify such expenditures. Shortly after the events of September 11, 2001, the Company completed a security assessment of its principal facilities. Because of recent changes in insurance markets, insurance coverages available to the Company have become more costly in recent years and in some cases less available. So long as this current trend continues, the Company expects to incur higher insurance costs and anticipates that, in some cases, it may be necessary to reduce somewhat the extent of insurance coverages because of reduced insurance availability at acceptable premium costs.

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 — 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 based upon generally accepted accounting principles: however, the amounts included in the EBITDA calculation are derived from amounts included in the consolidated financial statements of the Company. EBITDA should not be considered as an alternative to net income or operating income, as an indication of operating performance of the Company 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 enhances an investor’s understanding of the Company’s ability to satisfy principal and interest obligations with respect to the Company’s indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used by the Company management for internal analysis and as a basis for financial covenants.

                                 
    Years Ended December 31,
  Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands)
Net Income
  $ 46,053     $ 18,825     $ 32,029     $ 73,450  
Add provision for income tax
    28,306       10,159       18,867       48,445  
Add interest expense
    2,136       2,488       2,953       4,980  
Subtract interest income
    (458 )     (980 )     (1,528 )     (2,513 )
Add depreciation and amortization.
    36,275       28,550       27,699       27,327  
 
   
 
     
 
     
 
     
 
 
EBITDA
  $ 112,312     $ 59,042     $ 80,020     $ 151,689  
 
   
 
     
 
     
 
     
 
 

Reconciliations of refinery operating information to amounts reported under generally accepted accounting principles in financial statements.

Per barrel sales, material cost, operating cost and margins are used by management and others to compare refinery performance to other companies in the industry. Refinery gross margin is the difference between net sales price per barrel and raw material costs per barrel of produced refined products. Net cash operating margin is the difference between refinery gross margin per barrel and refinery operating cost per barrel. Other companies may not calculate

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margins in the same manner. Per barrel sales, material cost, and operating cost of produced refined products can be reconciled to the Company’s Statement of Income. Refining segment sales can be calculated by taking the sum of produced refined products (or calculated on a refinery stand alone basis) times the average sales price per produced barrel sold and purchased refined products times the average sales price per purchased barrel sold, times the number of days in the period. Refining segment costs of products sold would be calculated in the same manner. Refining operating expenses would be calculated by taking the sum of produced refined products sold (or calculated on a refinery stand alone basis) times the average cash operating cost per barrel produced, times the number of days in the period. Due to rounding of reported numbers, some amounts may not calculate exactly. The average produced barrel per day net sales, raw material costs, and refinery operating cost are reconciled to sales and other revenue, cost of product sold, and operating expenses as follows:

                                 
    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
Navajo Refinery
                               
Sales of produced refined products (BPD)
    62,570       64,270       59,830       62,620  
Average per produced barrel
                               
Net sales
  $ 38.95     $ 32.38     $ 31.02     $ 39.89  
Raw material costs.
    31.52       26.66       24.46       30.17  
 
   
 
     
 
     
 
     
 
 
Refinery gross margin
    7.43       5.72       6.56       9.72  
Refinery operating expenses
    3.24       2.70       2.84       2.92  
 
   
 
     
 
     
 
     
 
 
Net cash operating margin
  $ 4.19     $ 3.02     $ 3.72     $ 6.80  
 
   
 
     
 
     
 
     
 
 
Woods Cross Refinery
                               
Sales of produced refined products (BPD)
    22,480 (1)                        
Average per produced barrel
                               
Net sales
  $ 40.91                          
Raw material costs.
    34.81                          
 
   
 
                         
Refinery gross margin
    6.10                          
Refinery operating expenses
    3.92                          
 
   
 
                         
Net cash operating margin
  $ 2.18                          
 
   
 
                         
Montana Refinery
                               
Sales of produced refined products (BPD)
    7,150       6,940       7,230       6,460  
Average per produced barrel
                               
Net sales
  $ 35.80     $ 30.65     $ 30.38     $ 36.83  
Raw material costs
    28.17       23.79       22.23       26.22  
 
   
 
     
 
     
 
     
 
 
Refinery gross margin
    7.63       6.86       8.15       10.61  
Refinery operating expenses
    5.85       5.67       5.55       5.84  
 
   
 
     
 
     
 
     
 
 
Net cash operating margin
  $ 1.78     $ 1.19     $ 2.60     $ 4.77  
 
   
 
     
 
     
 
     
 
 

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    Years Ended December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands, except barrel data)
Consolidated
                               
Sales of produced refined products (BPD)
    82,900 (1)     71,210       67,060       69,080  
Average per produced barrel
                               
Net sales
  $ 38.99     $ 32.22     $ 30.95     $ 39.60  
Raw material costs
    31.76       26.38       24.22       29.80  
 
   
 
     
 
     
 
     
 
 
Refinery gross margin
    7.23       5.84       6.73       9.80  
Refinery operating expenses
    3.58       2.99       3.13       3.19  
 
   
 
     
 
     
 
     
 
 
Net cash operating margin
  $ 3.65     $ 2.85     $ 3.60     $ 6.61  
 
   
 
     
 
     
 
     
 
 
Sales of produced refined products (BPD)
    82,900       71,210       67,060       69,080  
Average sales price per produced barrel sold
  $ 38.99     $ 32.22     $ 30.95     $ 39.60  
Average raw material costs per produced barrel sold
  $ 31.76     $ 26.38     $ 24.22     $ 29.80  
Average cash operating expenses per produced barrel sold
  $ 3.58     $ 2.99     $ 3.13     $ 3.19  
                                 
Sales of purchased refined products (BPD)
    12,520       8,970       9,360       7,920  
Average sales price per purchased barrel sold
  $ 42.22     $ 35.13     $ 32.33     $ 41.72  
Average cost per purchased barrel sold
  $ 41.73     $ 34.15     $ 30.98     $ 41.64  
                                 
Sales of all refined products (BPD)
    95,420       80,180       76,420       77,000  
Average sales price per barrel sold
  $ 39.41     $ 32.54     $ 31.11     $ 39.82  
Average costs of products per barrel sold
  $ 33.07     $ 27.25     $ 25.04     $ 31.02  
                                 
Refined product sales
  $ 1,372,583     $ 952,306     $ 867,812     $ 1,119,141  
Other refining segment revenue
    823       1,002       918       1,107  
 
   
 
     
 
     
 
     
 
 
Total refining segment revenue
    1,373,406       953,308       868,730       1,120,248  
Pipeline transportation segment sales & other revenues
    21,030       19,078       18,588       18,454  
Corporate and other revenues and eliminations
    8,808       1,303       1,588       3,428  
 
   
 
     
 
     
 
     
 
 
Sales and other revenues
  $ 1,403,244     $ 973,689     $ 888,906     $ 1,142,130  
 
   
 
     
 
     
 
     
 
 
Refining segment cost of products sold
  $ 1,151,772     $ 797,490     $ 698,530     $ 871,814  
Corporate and other costs and eliminations
    4,086       (544 )     (285 )     (493 )
 
   
 
     
 
     
 
     
 
 
Cost of products sold
  $ 1,155,858     $ 796,946     $ 698,245     $ 871,321  
 
   
 
     
 
     
 
     
 
 
Refinery operating expenses
  $ 108,188     $ 77,755     $ 76,565     $ 80,519  
Other refining segment operating expenses(2)
    15,652       13,625       13,545       13,394  
 
   
 
     
 
     
 
     
 
 
Total refining segment operating expenses
    123,840       91,380       90,110       93,913  
Pipeline transportation segment operating expenses
    4,182       6,138       6,179       6,497  
Corporate and other costs and eliminations
    3,023       281              
 
   
 
     
 
     
 
     
 
 
Operating expenses
  $ 131,045     $ 97,799     $ 96,289     $ 100,410  
 
   
 
     
 
     
 
     
 
 


(1)   The Company purchased the Woods Cross, Utah refinery from ConocoPhillips on June 1, 2003. Barrels per day for Woods Cross is calculated based on actual production of the plant since June 1, 2003 (4,810,453 bbls divided by 214 days equals 22,480 BPD). For annual consolidation purposes, the Woods Cross barrels per day is calculated over 365 days (4,810,453 bbls divided by 365 days equals 13,180 BPD).
 
(2)   Represents refining segment expenses of product pipelines and terminals, principally relating to the marketing of products from the Navajo Refinery.

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Item 8. Financial Statements and Supplementary Data

     Index to Consolidated Financial Statements

         
    Page
    Reference
Report of Independent Auditors
    47  
Consolidated Balance Sheet at December 31, 2003 and 2002, and July 31, 2002
    48  
Consolidated Statement of Income for the years ended December 31, 2003 and 2002 (unaudited), five months ended December 31, 2002, and years ended July 31, 2002 and 2001
    49  
Consolidated Statement of Cash Flows for the years ended December 31, 2003 and 2002 (unaudited), five months ended December 31, 2002, and years ended July 31, 2002 and 2001
    50  
Consolidated Statement of Stockholders’ Equity for the year ended December 31, 2003, five months ended December 31, 2002, and years ended July 31, 2001 and 2000
    51  
Consolidated Statement of Comprehensive Income for the years ended December 31, 2003 and 2002 (unaudited), five months ended December 31, 2002, and years ended July 31, 2002 and 2001
    52  
Notes to Consolidated Financial Statements
    53  

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REPORT OF INDEPENDENT AUDITORS

The Board of Directors
and Stockholders of Holly Corporation

We have audited the accompanying consolidated balance sheets of Holly Corporation at December 31, 2003 and 2002 and July 31, 2002, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for the year ended December 31, 2003, the five months ended December 31, 2002, and each of the fiscal years ended July 31, 2002 and July 31, 2001. 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 auditing standards generally accepted in the 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Corporation at December 31, 2003 and 2002 and July 31, 2002, and the consolidated results of its operations and its cash flows for the year ended December 31, 2003, the five months ended December 31, 2002, and each of the fiscal years ended July 31, 2002 and July 31, 2001, in conformity with accounting principles generally accepted in the United States.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 19, 2004

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HOLLY CORPORATION

CONSOLIDATED BALANCE SHEET

                         
    December 31,   December 31,   July 31,
    2003
  2002
  2002
    (In thousands, except share data)
Assets
                       
Current assets
                       
Cash and cash equivalents
  $ 11,690     $ 24,266     $ 71,630  
Accounts receivable
    184,333       148,158       135,395  
Inventories
    112,347       61,137       45,308  
Income taxes receivable
    7,806       647       8,699  
Prepayments and other
    20,230       20,139       17,812  
 
   
 
     
 
     
 
 
Total current assets
    336,406       254,347       278,844  
Properties, plants and equipment, net
    304,244       214,150       199,461  
Investments in and advances to joint ventures
    13,850       15,955       15,732  
Other assets
    54,392       31,341       8,269  
 
   
 
     
 
     
 
 
Total assets
  $ 708,892     $ 515,793     $ 502,306  
 
   
 
     
 
     
 
 
Liabilities and Stockholders’ Equity
                       
Current liabilities
                       
Accounts payable
  $ 277,897     $ 207,418     $ 185,058  
Accrued liabilities
    28,199       25,913       25,342  
Credit agreement borrowings
    50,000              
Current maturities of long-term debt
    8,571       8,571       8,571  
 
   
 
     
 
     
 
 
Total current liabilities
    364,667       241,902       218,971  
Deferred income taxes
    50,331       28,254       29,065  
Long-term debt, less current maturities
    8,571       17,143       25,714  
Other long-term liabilities
    2,239              
Commitments and contingencies
                 
Minority interest in joint venture
    14,475              
Stockholders’ equity
                       
Preferred stock, $1.00 par value - 1,000,000 shares authorized; none issued
                 
Common stock, $.01 par value - 20,000,000 shares authorized; 16,885,896, 16,846,696 and 16,759,396 shares issued as of December 31, 2003, December 31, 2002, and July 31, 2002
    169       168       168  
Additional capital
    15,818       15,221       14,013  
Retained earnings
    264,991       225,759       223,770  
Accumulated other comprehensive income (loss)
    130       (1,049 )      
Common stock held in treasury, at cost - 1,371,868, 1,328,868, and 1,197,968 shares as of December 31, 2003, December 31, 2002, and July 31, 2002
    (12,499 )     (11,605 )     (9,395 )
 
   
 
     
 
     
 
 
Total stockholders’ equity
    268,609       228,494       228,556  
 
   
 
     
 
     
 
 
Total liabilities and stockholders’ equity
  $ 708,892     $ 515,793     $ 502,306  
 
   
 
     
 
     
 
 

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENT OF INCOME

                                         
                       
                    Five Months    
    Years Ended December 31,
  Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002 (Unaudited)
  2002
  2002
  2001
    (In thousands, except per share data)
Sales and other revenues
  $ 1,403,244     $ 973,689     $ 448,637     $ 888,906     $ 1,142,130  
Operating costs and expenses
                                       
Cost of products sold (exclusive of depreciation, depletion, and amortization)
    1,155,858       796,946       377,538       698,245       871,321  
Operating expenses (exclusive of depreciation, depletion, and amortization)
    131,045       97,799       41,566       96,289       100,410  
Selling, general and administrative expenses (exclusive of depreciation, depletion, and amortization)
    34,782       22,029       9,025       22,248       23,123  
Depreciation, depletion and amortization
    36,275       28,550       11,726       27,699       27,327  
Exploration expenses, including dry holes
    1,031       1,315       392       1,379       2,042  
 
   
 
     
 
     
 
     
 
     
 
 
Total operating costs and expenses
    1,358,991       946,639       440,247       845,860       1,024,223  
 
   
 
     
 
     
 
     
 
     
 
 
Gain on sale of assets
    15,814                          
 
   
 
     
 
     
 
     
 
     
 
 
Income from operations
    60,067       27,050       8,390       43,046       117,907  
Other income (expense)
                                       
Equity in earnings of joint ventures
    1,398       3,442       726       7,753       5,302  
Minority interest in income of joint venture
    (758 )                        
Interest income
    458       980       415       1,528       2,513  
Interest expense
    (2,136 )     (2,488 )     (1,014 )     (2,953 )     (4,980 )
Reparations payment received
    15,330                          
Other income
                      1,522       1,153  
 
   
 
     
 
     
 
     
 
     
 
 
 
    14,292       1,934       127       7,850       3,988  
 
   
 
     
 
     
 
     
 
     
 
 
Income before income taxes
    74,359       28,984       8,517       50,896       121,895  
Income tax provision (benefit)
                                       
Current
    8,009       7,574       4,613       14,533       44,577  
Deferred
    20,297       2,585       (1,499 )     4,334       3,868  
 
   
 
     
 
     
 
     
 
     
 
 
 
    28,306       10,159       3,114       18,867       48,445  
 
   
 
     
 
     
 
     
 
     
 
 
Net income
  $ 46,053     $ 18,825     $ 5,403     $ 32,029     $ 73,450  
 
   
 
     
 
     
 
     
 
     
 
 
Net income per common share — basic
  $ 2.97     $ 1.21     $ 0.35     $ 2.06     $ 4.84  
 
   
 
     
 
     
 
     
 
     
 
 
Net income per common share — diluted
  $ 2.88     $ 1.18     $ 0.34     $ 2.01     $ 4.77  
 
   
 
     
 
     
 
     
 
     
 
 
Cash dividends declared per common share
  $ 0.44     $ 0.44     $ 0.11     $ 0.41     $ 0.37  
 
   
 
     
 
     
 
     
 
     
 
 
Average number of common shares outstanding:
                                       
Basic
    15,505       15,557       15,516       15,560       15,187  
Diluted
    16,016       15,924       15,902       15,971       15,387  

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

                                         
                       
                    Five Months    
    Years Ended December 31,
  Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002 (Unaudited)
  2002
  2002
  2001
    (In thousands)
Cash flows from operating activities
                                       
Net income
  $ 46,053     $ 18,825     $ 5,403     $ 32,029     $ 73,450  
Adjustments to reconcile net income to net cash provided by operating activities
                                       
Depreciation, depletion and amortization
    36,275       28,550       11,726       27,699       27,327  
Deferred income taxes
    20,297       2,585       (1,499 )     4,334       3,868  
Dry hole costs and leasehold impairment
          289             289       955  
Minority interest in income of joint venture
    758                          
Equity in earnings of joint ventures
    (1,398 )     (3,442 )     (726 )     (7,753 )     (5,302 )
Gain on sale of assets
    (15,814 )                        
(Increase) decrease in current assets
                                       
Accounts receivable
    (35,547 )     (37,248 )     (12,763 )     10,107       44,821  
Inventories
    (17,453 )     (2,957 )     (15,829 )     4,828       6,463  
Income taxes receivable
    (6,931 )     (263 )     8,292       (4,731 )     (2,385 )
Prepayments and other
    995       (5,250 )     (594 )     (4,186 )     (378 )
Increase (decrease) in current liabilities
                                       
Accounts payable
    64,242       54,169       22,360       3,876       (42,688 )
Accrued liabilities
    2,000       (4,382 )     (1,570 )     (4,630 )     6,967  
Income taxes payable
          (468 )           (4,661 )     (1,516 )
Turnaround expenditures
    (25,029 )     172       (62 )     (13,931 )     (4,820 )
Prepaid transportation
          (25,000 )     (25,000 )            
Other, net
    2,308       1,743       1,529       (969 )     8  
 
   
 
     
 
     
 
     
 
     
 
 
Net cash provided by (used for) operating activities
    70,756       27,323       (8,733 )     42,301       106,770  
Cash flows from investing activities
                                       
Additions to properties, plants and equipment
    (74,642 )     (47,701 )     (22,793 )     (35,313 )     (28,571 )
Acquisition of Woods Cross refinery and retail stations
    (55,837 )     (2,500 )     (2,500 )            
Investments and advances to joint ventures
    (3,328 )     (3,250 )           (3,250 )     (5,874 )
Purchase of additional interest in joint venture, net of cash
    (21,369 )                        
Distributions from joint ventures
    4,918       11,024       524       11,650       5,693  
Proceeds from the sale of marketable equity securities
                      4,500        
Proceeds from the sale of partial interest in joint venture
          460             460        
Cash distributions to minority interests
    (1,350 )                        
Proceeds from sale of retail stations
    8,462                          
Proceeds from the sale of pipeline assets
    24,000                          
 
   
 
     
 
     
 
     
 
     
 
 
Net cash used for investing activities
    (119,146 )     (41,967 )     (24,769 )     (21,953 )     (28,752 )
Cash flows from financing activities
                                       
Payment of long-term debt
    (8,572 )     (8,571 )     (8,571 )     (8,572 )     (13,738 )
Increase in borrowings, net under revolving credit agreement
    50,000                          
Debt issuance costs
    (185 )     (635 )     (635 )           (829 )
Issuance of common stock upon exercise of options
    369       1,821       968       1,993       4,386  
Purchase of treasury stock
    (894 )     (3,652 )     (2,210 )     (1,602 )      
Cash dividends
    (5,114 )     (6,686 )     (3,414 )     (6,377 )     (5,625 )
Other
    210                          
 
   
 
     
 
     
 
     
 
     
 
 
Net cash provided by (used for) financing activities
    35,814       (17,723 )     (13,862 )     (14,558 )     (15,806 )
Cash and cash equivalents
                                       
Increase (decrease) for the period
    (12,576 )     (32,367 )     (47,364 )     5,790       62,212  
Beginning of period
    24,266       56,633       71,630       65,840       3,628  
 
   
 
     
 
     
 
     
 
     
 
 
End of period
  $ 11,690     $ 24,266     $ 24,266     $ 71,630     $ 65,840  
 
   
 
     
 
     
 
     
 
     
 
 

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

                                                 
                            Accumulated            
                            Other            
                            Comprehensive           Total
    Common   Additional   Retained   Income   Treasury   Stockholders'
    Stock
  Capital
  Earnings
  (Loss)
  Stock
  Equity
    (In thousands)
Balance at July 31, 2000
  $ 87     $ 6,132     $ 130,293     $ 862     $ (7,793 )   $ 129,581  
Net income
                73,450                   73,450  
Dividends paid
                (5,625 )                 (5,625 )
Other comprehensive loss
                      (1,187 )           (1,187 )
Issuance of common stock upon exercise of stock options
    1       5,514                         5,515  
Two-for-one stock split
    78       (78 )                        
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Balance at July 31, 2001
  $ 166     $ 11,568     $ 198,118     $ (325 )   $ (7,793 )   $ 201,734  
Net income
                32,029                   32,029  
Dividends paid
                (6,377 )                 (6,377 )
Other comprehensive income
                      325             325  
Issuance of common stock upon exercise of stock options
    2       2,445                         2,447  
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 paid
                (3,414 )                 (3,414 )
Other comprehensive income
                      (1,049 )           (1,049 )
Issuance of common stock upon exercise of stock options
          1,208                         1,208  
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       597                         598  
Purchase of treasury stock
                            (894 )     (894 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Balance at December 31, 2003
  $ 169     $ 15,818     $ 264,991     $ 130     $ (12,499 )   $ 268,609  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

                                         
    Years Ended December 31,
  Five Months
Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002 (Unaudited)
  2002
  2002
  2001
    (In thousands)
Net income
  $ 46,053     $ 18,825     $ 5,403     $ 32,029     $ 73,450  
Other comprehensive income (loss)
Unrealized income on securities available for sale
                            88  
Reclassification adjustment to net income on sale of equity securities
                      (1,522 )      
Other income (loss) on pension obligation
    1,362       (1,747 )     (1,747 )            
Derivative instruments qualifying as cash flow hedging instruments
                                       
Change in fair value of derivative instruments
    373       6       47       (1,188 )     (2,669 )
Reclassification adjustment into net income
    179       1,501             3,250       607  
 
   
 
     
 
     
 
     
 
     
 
 
Total income (loss) on cash flow hedges
    1,914       (240 )     (1,700 )     540       (1,974 )
 
   
 
     
 
     
 
     
 
     
 
 
Other comprehensive income (loss) before income taxes
    1,914       (240 )     (1,700 )     540       (1,974 )
Income tax expense (benefit)
    735       (81 )     (651 )     215       (787 )
 
   
 
     
 
     
 
     
 
     
 
 
Other comprehensive income (loss)
    1,179       (159 )     (1,049 )     325       (1,187 )
 
   
 
     
 
     
 
     
 
     
 
 
Total comprehensive income
  $ 47,232     $ 18,666     $ 4,354     $ 32,354     $ 72,263  
 
   
 
     
 
     
 
     
 
     
 
 

See accompanying notes.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Description of Business: Holly Corporation, and its consolidated subsidiaries, herein referred to as the “Company” unless the context otherwise indicates, is principally an independent petroleum refiner, which produces high value light products such as gasoline, diesel fuel and jet fuel. Navajo Refining Company, L.P., (“Navajo”), one of the Company’s 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 barrels-per-day (“BPD”), can process a variety of 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 BPD. In June, 2003, the Company 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, has a crude capacity of 25,000 BPD and is operated by Holly Refining & Marketing Company, one of the Company’s wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes sweet (lower sulfur) crude oil. The Company also owns Montana Refining Company, a Partnership (“MRC”), which owns a 7,000 BPD petroleum refinery in Great Falls, Montana (“Montana Refinery”), which can process a variety of sour crude oils and which primarily serves markets in Montana. In conjunction with the refining and pipeline operations, the Company owns or leases approximately 2,000 miles of pipelines. The Company owns and operates nine refined product terminals in Artesia, Moriarty, Bloomfield and Lovington, New Mexico, El Paso, Texas, Woods Cross, Utah, Spokane, Washington, Great Falls, Montana, and in Mountain Home, Idaho and owns interest in four product storage facilities in Albuquerque, New Mexico, Tucson, Arizona, Burley and Boise, Idaho. In recent years, the Company has made an effort to develop and expand a pipeline transportation business generating revenues from unaffiliated parties. The pipeline transportation operations include approximately 500 miles of the 2,000 miles of pipeline that the Company owns and operates. Additionally, the Company has a 70% interest (25% interest prior to June 30, 2003) in Rio Grande Pipeline Company, which provides transportation of liquid petroleum gases (“LPG”) to northern Mexico, and 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. The Company also conducts a small-scale oil and gas exploration and production program and has a small investment in a joint venture that operates retail gasoline stations and convenience stores in Montana.

Change in Year-End: On July 30, 2003, the Company changed its 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. For comparative purposes, an unaudited income statement, statement of cash flows and other comprehensive income has been included for the year ended December 31, 2002. The reported numbers for the year ended December 31, 2002, which have not been audited, are derived from the books and records of the Company and in the opinion of management reflect all adjustments necessary to present the financial position and results of operations in accordance with generally accepted accounting principles.

Principles of Consolidation: The consolidated financial statements include the accounts of the Company and its subsidiary corporations, partnerships, limited liability companies, and joint ventures where it has ownership of more than 50%. All significant intercompany transactions and balances have been eliminated. The accounts of Rio Grande Pipeline Company were consolidated as of June 30, 2003.

Use of Estimates: The preparation of financial statements in accordance with 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.

Reclassifications: Certain reclassifications have been made for prior periods to conform to the classifications used in 2003.

Cash Equivalents: For purposes of the statement of cash flows, the Company considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents.

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,

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

such as letters of credit or guarantees, is required. Credit losses are charged to income when accounts are deemed uncollectible and consistently 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: The Company calculates depreciation and amortization based on estimated useful lives and salvage values of its assets. The Company evaluates 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 2003, the five months ended December 31, 2002, or the fiscal years ended July 31, 2002 and 2001.

Investments in Joint Ventures: The Company accounts for investments in and earnings from joint ventures, where it has ownership of 50% or less, using the equity method.

Investments in Equity Securities: Investments in equity securities are classified as available-for-sale and are reported at fair value with unrealized gains or losses, net of tax, recorded as other comprehensive income.

Prepaid Transportation Costs: As a result of the Company’s settlement of litigation with Longhorn Partners, the Company in November 2002 prepaid $25,000,000 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 6 years from the date the Longhorn Pipeline begins operations if such operations begin by July 1, 2004. Under the agreement, the prepayment would cover shipments of 7,000 BPD by the Company for approximately 4 1/2 years assuming there were no curtailments of service once operations began. The Company plans to make use of the prepaid transportation services to ship purchased refined products on the Longhorn Pipeline and will amortize the prepaid costs as refined products are shipped. Under the terms of the November 2002 settlement agreement that terminated litigation between the Company and Longhorn Partners, the Company would have an unsecured claim for repayment with interest of the Company’s $25,000,000 prepayment to Longhorn Partners for transportation services in the event the Longhorn Pipeline did not begin operations by July 1, 2004 or announced that it would not begin operations by that date. At the date of this report, it is not possible to predict whether and, if so, under what conditions, the Longhorn Pipeline will ultimately be operated, nor is it possible to predict the overall impact on the Company if the Longhorn Pipeline does not ultimately begin operations or begins operations at different possible future dates. If it becomes probable that the Longhorn Pipeline will not become operational or if there is indication of impairment in the value of the prepaid transportation costs, the Company would record an impairment loss equal to the amount by which the carrying value exceeds the fair value.

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 through Company operated pipelines. Crude oil buy/sell exchanges are customarily used in association with operation of the pipelines, with only the net differential of such transactions reflected as revenues. Additional pipeline transportation revenues result from the lease of an interest in the capacity of a Company operated 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 goods 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.

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, the Company purchases crude oil from producers and other petroleum companies in excess of the needs of its 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

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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: The Company’s 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: The Company is subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. The Company is 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: The Company accounts for the acquisition, exploration, development and production costs of its oil and gas activities using the successful efforts method of accounting. Lease acquisition costs are capitalized; 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, 2003, the Company 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. The Company has elected, as permitted by the standard, to continue to follow its 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 the Company’s stock at the measurement date over the exercise price. The Company has 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.

Derivative Instruments: Effective as of August 1, 2000, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. This Statement 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 Statement requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. See Note 14 for additional information on derivative instruments and hedging activities.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Pronouncements:

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 142 “Goodwill and Other Intangible Assets” which changes how goodwill and other intangible assets are accounted for subsequent to their initial recognition. SFAS No. 142 was effective for fiscal years beginning after December 15, 2001. The Company adopted the standard effective August 1, 2002 and there was no effect on its financial condition, results of operations, or cash flows.

In June 2001, FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” which requires that the fair value for an asset retirement obligation be capitalized as part of the carrying amount of the long-lived asset if a reasonable estimate of fair value can be made. SFAS No. 143 was effective for fiscal years beginning after June 15, 2002. The Company adopted the standard effective August 1, 2002 and there was no material effect on the Company’s financial condition, results of operations, or cash flows.

In August 2001, FASB issued SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This statement supersedes SFAS No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of”, but carries over the key guidance from SFAS No. 121 in establishing the framework for the recognition and measurement of long-lived assets to be disposed of by sale and addresses significant implementation issues. SFAS No. 144 was effective for fiscal years beginning after December 15, 2001. The Company adopted the standard effective August 1, 2002 and there was no effect on its financial condition, results of operations, or cash flows.

In June 2002, FASB issued SFAS No. 146 “Accounting for Certain Costs Associated with Exit or Disposal Activities” which nullifies Emerging Issues Task Force (“EITF”) 94-3 and requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and establishes fair value as the objective for initial measurement of liabilities. This differs from EITF 94-3 which stated that liabilities for exit costs were to be recognized as of the date of an entity’s commitment to an exit plan. SFAS No. 146 was effective for exit or disposal activities that are initiated after December 31, 2002. The Company adopted the standard on January 1, 2003, and there was no effect on its financial condition, results of operations, or cash flows.

In December 2002, FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure,” an amendment of SFAS No. 123. This statement provides alternative methods of transition to SFAS No. 123’s fair value method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148’s amendment of the disclosure requirements was effective for interim periods beginning after December 15, 2002. SFAS No. 148’s amendment of the transition and annual disclosure requirements of SFAS 123 was effective for fiscal years ending after December 15, 2002. See Note 3 to the Consolidated Financial Statements for effect of this standard on the Company’s financial condition, results of operations, and cash flows.

In January 2003, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The Company adopted the standard on January 1, 2003 and there was no material effect on its financial condition, results of operations, or cash flows.

In January 2003 (revised December 2003), the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 requires an entity to consolidate a variable interest entity if it is designated as

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the primary beneficiary of that entity and if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of FIN 46 apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim period beginning after June 15, 2003. The Company is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of FIN 46 by the Company on December 31, 2003 had no effect on the Company’s financial condition, results of operations, or cash flows.

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement will result in a more complete depiction of an entity’s liabilities and equity and will thereby assist investors and creditors in assessing the amount, timing, and likelihood of potential future cash outflows and equity share issuances. This statement is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. It is to be implemented by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of the statement and still existing at the beginning of the interim period of adoption. Restatement is not permitted. The Company adopted the standard on July 1, 2003, and there was no effect on its financial condition, results of operations, or cash flows.

In December 2003, the FASB issued SFAS No. 132 (revised), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” These revisions require 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 statement now requires interim period disclosures regarding net periodic pension cost and employer contributions. The statement is effective for fiscal years ending after December 15, 2003. The Company adopted the standard on December 31, 2003.

The American Institute of Certified Public Accountants has issued an Exposure Draft for a Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment,” which would require major maintenance activities to be expensed as costs are incurred. As of December 31, 2003, the Company had approximately $24.7 million of deferred maintenance costs, all relating to refinery turnarounds in prior periods, which are being amortized over various benefit periods. The current monthly amortization is $737,000. If this proposed Statement of Position had been adopted in its current form, as of December 31, 2003, the Company would have been required to expense $24.7 million of deferred maintenance costs and would be required to expense all future turnaround costs as incurred.

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NOTE 2: Earnings Per Share

Basic income per share is calculated as net income divided by average number of shares of common stock outstanding. Diluted income per share assumes, when dilutive, issuance of the net incremental shares from stock options. Income per share amounts reflect the two-for-one stock split in July 2001. The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations for income:

                                 
               
      Five Months    
    Year Ended
December 31,
  Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands, except per share data)
Net income
  $ 46,053     $ 5,403     $ 32,029     $ 73,450  
               
Average number of shares of common stock outstanding
    15,505       15,516       15,560       15,187  
Effect of dilutive stock options.
    511       386       411       200  
 
   
 
     
 
     
 
     
 
 
Average number of shares of common stock outstanding assuming dilution
    16,016       15,902       15,971       15,387  
 
   
 
     
 
     
 
     
 
 
Income per share — basic
  $ 2.97     $ 0.35     $ 2.06     $ 4.84  
 
   
 
     
 
     
 
     
 
 
Income per share — diluted
  $ 2.88     $ 0.34     $ 2.01     $ 4.77  
 
   
 
     
 
     
 
     
 
 

NOTE 3: Stock-Based Compensation

The Company has 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. The Company’s stock-based compensation is measured in accordance with the 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, the Company has determined pro-forma information as if it had accounted for stock options granted under the fair value method of SFAS No. 123. The weighted-average fair value of options granted was $4.25 per share in fiscal 2002 and $3.17 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 voliatility factor .
    49.6 %     32.0 %
Weighted-average expected life of options
  6 years   6 years

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

                                 
               
      Five Months  
    Year Ended
December 31,
  Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands, except per share data)
Net income, as reported
  $ 46,053     $ 5,403     $ 32,029     $ 73,450  
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects
    453       189       465       591  
 
   
 
     
 
     
 
     
 
 
Pro forma net income
    45,600       5,214       31,564       72,859  
 
   
 
     
 
     
 
     
 
 
Net income per share — basic
As reported
  $ 2.97     $ 0.35     $ 2.06     $ 4.84  
Pro forma
  $ 2.94     $ 0.34     $ 2.03     $ 4.80  
Net income per share — diluted
As reported
  $ 2.88     $ 0.34     $ 2.01     $ 4.77  
Pro forma
  $ 2.85     $ 0.33     $ 1.98     $ 4.74  

NOTE 4: Accounts Receivable

                         
    December 31,
  July 31,
    2003
  2002
  2002
    (In thousands)
Product and transportation
  $ 68,662     $ 51,141     $ 46,929  
Crude oil resales.
    115,671       97,017       88,466  
 
   
 
     
 
     
 
 
 
  $ 184,333     $ 148,158     $ 135,395  
 
   
 
     
 
     
 
 

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.

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NOTE 5: Inventories

                         
    December 31,
  July 31,
    2003
  2002
  2002
    (In thousands)
Crude oil
  $ 34,545     $ 14,636     $ 5,431  
Other raw materials and unfinished products(1)
    14,006       4,684       5,706  
Finished products(2)
    52,098       31,488       23,983  
Process chemicals(3)
    4,842       4,114       3,986  
Repairs and maintenance supplies and other
    6,856       6,215       6,202  
 
   
 
     
 
     
 
 
 
  $ 112,347     $ 61,137     $ 45,308  
 
   
 
     
 
     
 
 

(1)   Other raw materials and unfinished products include feedstocks and blendstocks, other than crude. The carrying value includes the cost of the raw materials and transportation.
 
(2)   Finished products include gasolines, jet fuels, diesels, asphalts, LPGs 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 $39,894,000 at December 31, 2003, $35,307,000 at December 31, 2002 and $30,148,000 at July 31, 2002. The Company recognized $2,253,000 in income in the fiscal year ended July 31, 2002 resulting from liquidations of certain LIFO inventory quantities that were carried at lower costs as compared to current costs in 2002.

NOTE 6: Properties, Plants and Equipment

                         
    December 31,
  July 31,
    2003
  2002
  2002
    (In thousands)
Land, buildings and improvements
  $ 19,501     $ 15,191     $ 15,082  
Refining facilities
    335,483       211,354       210,806  
Pipelines and terminals
    137,785       121,215       119,581  
Transportation vehicles
    18,846       17,160       16,595  
Oil and gas exploration and development
    5,084       15,324       14,729  
Other fixed assets
    15,219       11,005       9,244  
Construction in progress
    3,997       43,043       24,950  
 
   
 
     
 
     
 
 
 
    535,915       434,292       410,987  
Accumulated depreciation, depletion and amortization
    (231,671 )     (220,142 )     (211,526 )
 
   
 
     
 
     
 
 
 
  $ 304,244     $ 214,150     $ 199,461  
 
   
 
     
 
     
 
 

During the year ended December 31, 2003, five months ended December 31, 2002, and year ended July 31, 2002, the Company capitalized $1,247,000, $711,000 and $1,138,000 respectively of interest related to major construction projects.

NOTE 7: Investments in Joint Ventures

In fiscal 1996, the Company entered into a joint venture, the Rio Grande Pipeline Company, to transport liquid petroleum gas to Mexico. The Company has a 70% interest in the joint venture, with the purchase effective June 30, 2003 of an additional 45% interest for $28.7 million. Prior to the 45% acquisition, the Company accounted for the

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earnings of the joint venture using the equity method. Effective with this purchase the Company consolidates the results of the Rio Grande Pipeline Company and reflects 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 the Company’s acquisition of the additional partnership interest. In addition to cash, at June 30, 2003, the Rio Grande Pipeline Company owned current assets of $.6 million, net property, plant and equipment of $34.9 million, other net assets of $7.8 million, and current liabilities of $.4 million.

In fiscal 1998, the Company invested in a joint venture (a limited liability company) to operate retail service stations and convenience stores in Montana. The Company has a 49% interest in the joint venture and accounts for earnings using the equity method. The Company has reserved approximately $800,000 related to the collectability of advances of $1,590,000 associated with this joint venture.

In fiscal 2000, the Company entered into a joint venture, NK Asphalt Partners, to manufacture and market asphalt products from various terminals in Arizona and New Mexico. The Company currently has a 49% interest in the joint venture and accounts for earnings using the equity method. In fiscal 2000, the Company contributed cash of $2,182,000, inventories with a net book value of $928,000 and properties with a net book value of $4,311,000 for a 50% ownership interest in the joint venture. Effective January 2002, the Company sold 1% of its 50% equity interest to the other joint venture partner. The Company is required to make additional contributions to the joint venture of up to $3,250,000 for each of the next seven years contingent on the earnings level of the joint venture.

The Company’s Navajo Refinery sells at market prices all of its produced asphalt to the NK Asphalt Partners joint venture. Sales to the joint venture during the year ended December 31, 2003, five months ended December 31, 2002, and years ended July 31, 2002 and July 31, 2001, were $31.0 million, $11.1 million, $22.6 million and $25.3 million, respectively.

NK Asphalt Partners Joint Venture (Unaudited):

                         
            Five Months   Fiscal
    Year Ended   Ended   Year Ended
    December 31,   December 31,   July 31,
    2003
  2002
  2002
    (In thousands)
Current assets
  $ 15,381     $ 22,050     $ 24,631  
Other assets
    12,738       13,095       13,263  
 
   
 
     
 
     
 
 
Total
  $ 28,119     $ 35,145     $ 37,894  
 
   
 
     
 
     
 
 
Current liabilities
  $ 4,614     $ 6,048     $ 8,878  
Long-term liabilities
    23       35       51  
Equity
    23,482       29,062       28,965  
 
   
 
     
 
     
 
 
Total
  $ 28,119     $ 35,145     $ 37,894  
 
   
 
     
 
     
 
 
Sales (net)
  $ 84,834     $ 33,713     $ 86,596  
 
   
 
     
 
     
 
 
Gross Profit
  $ 14,184     $ 4,667     $ 22,918  
 
   
 
     
 
     
 
 
Income from operations
  $ 2,603     $ 824     $ 13,217  
 
   
 
     
 
     
 
 
Net income before taxes
  $ 1,170     $ 97     $ 13,425  
 
   
 
     
 
     
 
 

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NOTE 8: Other Assets

                         
    December 31,
  July 31,
    2003
  2002
  2002
    (In thousands)
Prepaid transportation costs
  $ 25,000     $ 25,000     $  
Turnaround costs (long-term portion)
    18,909       2,205       7,004  
Intangibles and other
    10,483       4,136       1,265  
 
   
 
     
 
     
 
 
 
  $ 54,392     $ 31,341     $ 8,269  
 
   
 
     
 
     
 
 

NOTE 9: Environmental Costs

Consistent with the Company’s accounting policy for environmental remediation and cleanup costs, the Company expensed $3,892,000 in 2003 for environmental remediation and cleanup obligations. The accrued liability reflected in the consolidated balance sheet was $4,016,000 at December 31, 2003, of which $2,239,000 was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value. In the previous periods reported, the Company’s remediation and cleanup obligations expensed was not significant.

NOTE 10: Debt

                         
    December 31,
  July 31,
    2003
  2002
  2002
    (In thousands)
Senior Notes
                       
Series C
  $ 11,142     $ 16,714     $ 22,285  
Series D
    6,000       9,000       12,000  
 
   
 
     
 
     
 
 
 
    17,142       25,714       34,285  
Current maturities of long-tern debt
    (8,571 )     (8,571 )     (8,571 )
 
   
 
     
 
     
 
 
 
  $ 8,571     $ 17,143     $ 25,714  
 
   
 
     
 
     
 
 

Senior Notes: In November 1995, the Company completed the funding from a group of insurance companies of a new private placement of Senior Notes in the amount of $39 million and the extension of $21 million of previously outstanding Senior Notes. The $39 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 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 Agreement. The Company was in compliance with all covenants at December 31, 2003.

Credit Agreement: In April 2000, the Company and its subsidiaries entered into a credit agreement (“Credit Agreement”) with a group of banks. In May 2003, the Credit Agreement was amended and increased the commitment from $75 million to $100 million. The Company now has access to $100 million of commitments that can be used for revolving credit loans and letters of credit. Previously the Company had access to $75 million of commitments, of which only $37.5 million could be used for revolving credit loans. Interest on borrowings is based upon, at the Company’s option, (i) the higher of the agent bank’s prime rate plus a margin ranging from .25% to 1% or the Federal funds rate plus .50% per annum; or (ii) the London interbank offered rate (“LIBOR”) plus a margin ranging from 1.25% to 2.5%. A fee ranging from 1.25% to 2.5% per annum is payable on the outstanding balance of all letters of credit and a commitment fee ranging from .30% to .50% per annum is payable on the unused portion of the facility. Such interest rate margins and fees are determined based on a quarterly calculation of the ratio of

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cash flow to debt of the Company. The borrowing base, which secures the facility, consists of accounts receivable and inventory, and at the option of the Company, cash and cash equivalents. The Credit Agreement imposes certain requirements, including: (i) a prohibition of other indebtedness in excess of $5 million with exceptions for, among other things, indebtedness under the Company’s Senior Notes; (ii) maintenance of certain levels of net worth, working capital and a cash-flow-to-debt ratio; (iii) limitations on investments, capital expenditures and dividends; and (iv) a prohibition on changes in control. The Company was in compliance with all covenants at December 31, 2003.

At December 31, 2003, the Company had outstanding letters of credit totaling $4,180,000, and $50,000,000 in borrowings outstanding. At that level of usage, the unused commitment under the current Credit Agreement would be $45,820,000.

The average and maximum amounts outstanding and the effective average interest rate for borrowings under the Company’s Credit Agreement during the year ended December 31, 2003 were as follows:

         
    Year Ended
    December 31,
    2003
Average amount outstanding
  $ 15,879  
Maximum balance
  $ 65,000  
Effective average interest rate
    2.7 %

There were no borrowings outstanding under the Credit Agreement during the five months ended December 31, 2002 or in each of the fiscal years ended July 31, 2002 and 2001.

The Senior Notes and Credit Agreement restrict investments and distributions, including dividends. Under the most restrictive of these covenants, under the Credit Agreement, the Company is subject to a maximum of $10 million per year for the payment of dividends.

Long-term debt outstanding as of December 31, 2003 matures $8,571,000 in 2004 and $8,571,000 in 2005.

The Company made cash interest payments of $2,733,000 in 2003, $1,738,000 in the five months ended December 31, 2002, $3,765,501 in fiscal 2002, and $5,552,000 in fiscal 2001.

Based on the borrowing rates that the Company believes would be available for replacement loans with similar terms and maturities of the debt of the Company now outstanding, the Company estimates the fair value of long-term debt including current maturities to be approximately equal to the amount currently on the balance sheet of $17.1 million at December 31, 2003.

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NOTE 11: Income Taxes

The provision for income taxes is comprised of the following:

                                 
    Year Ended
December 31,
  Five Months
Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands)
Current
                               
Federal
  $ 6,720     $ 4,266     $ 12,317     $ 36,337  
State
    1,289       347       2,216       8,240  
Deferred
                               
Federal
    17,433       (1,187 )     4,072       3,184  
State
    2,864       (312 )     262       684  
 
   
 
     
 
     
 
     
 
 
 
  $ 28,306     $ 3,114     $ 18,867     $ 48,445  
 
   
 
     
 
     
 
     
 
 

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

                                 
    Year Ended
December 31,
  Five Months
Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands)
Tax computed at statutory rate
  $ 26,026     $ 2,981     $ 17,814     $ 42,663  
State income taxes, net of federal tax benefit
    2,658       332       1,985       5,942  
Other
    (378 )     (199 )     (932 )     (160 )
 
   
 
     
 
     
 
     
 
 
 
  $ 28,306     $ 3,114     $ 18,867     $ 48,445  
 
   
 
     
 
     
 
     
 
 

Prior to the acquisition of MRC by the Company, operations of the corporation that was the sole limited partner of MRC resulted in unused net operating loss carryforwards of approximately $9,000,000, which are expected to be available to the Company to a limited extent each year through 2006. As of December 31, 2003, approximately $1,400,000 of these net operating loss carryforwards remain available to offset future income. In fiscal 2002, the Company recognized a benefit of approximately $455,000 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 $95,000 per year through 2005 relating to the acquisition of such corporation.

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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. The Company’s deferred income tax assets and liabilities as of December 31, 2003 and 2002, and July 31, 2002 are as follows:

                         
    December 31, 2003
    Assets
  Liabilities
  Total
    (In thousands)
Deferred taxes
                       
Accrued employee benefits
  $ 1,830     $     $ 1,830  
Accrued postretirement benefits
    2,279             2,279  
Accrued environmental costs
    1,549             1,549  
Inventory valuation reserve
    629             629  
Deferred turnaround costs
          (3,026 )     (3,026 )
Pipeline lease
    527             527  
Prepayments and other
    197       (1,651 )     (1,454 )
 
   
 
     
 
     
 
 
Total current
    7,011       (4,677 )     2,334  
Properties, plants and equipment (due primarily to tax in excess of book depreciation)
          (43,338 )     (43,338 )
Deferred turnaround costs
          (6,503 )     (6,503 )
Investments in joint ventures
    29       (957 )     (928 )
Other
    974       (536 )     438  
 
   
 
     
 
     
 
 
Total noncurrent
    1,003       (51,334 )     (50,331 )
 
   
 
     
 
     
 
 
Total
  $ 8,014     $ (56,011 )   $ (47,997 )
 
   
 
     
 
     
 
 
                         
    December 31, 2002
    Assets
  Liabilities
  Total
    (In thousands)
Deferred taxes
                       
Accrued employee benefits
  $ 2,335     $     $ 2,335  
Accrued postretirement benefits
    2,283             2,283  
Inventory valuation reserve
    712             712  
Deferred turnaround costs
          (3,488 )     (3,488 )
Pipeline lease
    683             683  
Prepayments and other
    413       (1,649 )     (1,236 )
 
   
 
     
 
     
 
 
Total current
    6,426       (5,137 )     1,289  
Properties, plants and equipment (due primarily to tax in excess of book depreciation)
          (27,869 )     (27,869 )
Deferred turnaround costs
          (759 )     (759 )
Investments in joint ventures
    452       (626 )     (174 )
Other
    1,025       (477 )     548  
 
   
 
     
 
     
 
 
Total noncurrent
    1,477       (29,731 )     (28,254 )
 
   
 
     
 
     
 
 
Total
  $ 7,903     $ (34,868 )   $ (26,965 )
 
   
 
     
 
     
 
 

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    July 31, 2002
    Assets
  Liabilities
  Total
    (In thousands)
Deferred taxes
                       
Accrued employee benefits
  $ 2,016     $ (755 )   $ 1,261  
Accrued postretirement benefits
    1,820             1,820  
Inventory valuation reserve
    712             712  
Deferred turnaround costs
          (2,828 )     (2,828 )
Pipeline lease
    746             746  
Prepayments and other
    550       (2,311 )     (1,761 )
 
   
 
     
 
     
 
 
Total current
    5,844       (5,894 )     (50 )
Properties, plants and equipment (due primarily to tax in excess of book depreciation)
          (25,563 )     (25,563 )
Deferred turnaround costs
          (2,504 )     (2,504 )
Investments in joint ventures
          (1,638 )     (1,638 )
Other
    1,282       (642 )     640  
 
   
 
     
 
     
 
 
Total noncurrent
    1,282       (30,347 )     (29,065 )
 
   
 
     
 
     
 
 
Total
  $ 7,126     $ (36,241 )   $ (29,115 )
 
   
 
     
 
     
 
 

The Company made income tax payments of $15,043,000 in 2003, $3,959,000 in the five months ended December 31, 2002, $24,135,000 in fiscal 2002 and $48,356,000 in fiscal 2001.

NOTE 12: Stockholders’ Equity

Stock Option Plans: The Company has a long-term incentive compensation plan and a stock option plan under which certain officers and employees have been granted stock options. All of the options have been granted at prices equal to the market value of the shares at the time of grant and expire on the tenth anniversary of the grant date. The options are subject to forfeiture with vesting for all options outstanding at July 31, 1999 of 20% at the time of grant and 20% in each of the four years thereafter and vesting for all options granted subsequent to July 31, 1999 of 20% at the end of each of the five years after the grant date. At December 31, 2003, December 31, 2002 and July 31, 2002, 944,000 shares, respectively, of common stock were reserved for future grants under the current long-term incentive compensation plan, which allows for awards of options, restricted stock, or other performance awards.

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The following summarizes stock option transactions:

                 
            Weighted
            Average
            Exercise
    Shares
  Price
Balance at July 31, 2000
    1,366,000     $ 9.99  
Granted
    642,000       11.05  
Forfeited
    (6,000 )     13.38  
Exercised
    (379,000 )     11.57  
 
   
 
     
 
 
Balance at July 31, 2001
    1,623,000       10.02  
Granted
    50,000       19.80  
Exercised
    (179,300 )     11.11  
 
   
 
     
 
 
Balance at July 31, 2002
    1,493,700       10.22  
Exercised
    (87,300 )     11.09  
 
   
 
     
 
 
Balance at December 31, 2002
    1,406,400       10.17  
Exercised
    (39,200 )     9.41  
 
   
 
     
 
 
Balance at December 31, 2003
    1,367,200     $ 10.19  
 
   
 
     
 
 
Options exercisable at December 31, 2003
    822,200     $ 9.84  
Options exercisable at December 31, 2002
    604,000     $ 10.16  
Options exercisable at July 31, 2002
    513,700     $ 11.12  
Options exercisable at July 31, 2001
    315,000     $ 11.96  

The following summarizes information about stock options outstanding at December 31, 2003:

                                         
            Weighted                
            Average   Weighted           Weighted
            Remaining   Average           Average
    Number   Contractual   Exercise   Number   Exercise
Range of Exercise Price
  Outstanding
  Life (Yrs)
  Price
  Exercisable
  Price
$5.06 - $8.63
    633,400       5.96     $ 7.12       427,000     $ 7.11  
$11.90 - $13.38
    687,800       6.22       12.37       379,200       12.76  
$19.80
    46,000       7.99       19.80       16,000       19.80  
 
   
 
     
 
     
 
     
 
     
 
 
$5.06 - $19.80
    1,367,200       6.16     $ 10.19       822,200     $ 9.84  
 
   
 
     
 
     
 
     
 
     
 
 

Common Stock Repurchases: On October 30, 2001, the Company announced plans to repurchase up to $20 million of the Company’s common stock. Such repurchases have been made from time to time in open market purchases or privately negotiated transactions, subject to price and availability. The repurchases have been financed with available corporate funds. During the year ended December 31, 2003, the Company repurchased 43,000 shares at a cost of approximately $894,000 or an average of $20.79 per share. From inception of the plan through December 31, 2003, the Company has repurchased 272,400 shares at a cost of approximately $4.7 million. No stock repurchases have been made since February 7, 2003.

NOTE 13: Retirement Plans

Retirement Plan: The Company has a non-contributory defined benefit retirement plan that covers substantially all employees. The Company’s policy is to make contributions annually of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

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The following table sets forth the changes in the benefit obligation and plan assets of the Company’s retirement plan for the year ended December 31, 2003, five months ended December 31, 2002 and the fiscal year ended July 31, 2002:

                         
            Five Months   Fiscal
    Year Ended   Ended   Year Ended
    December 31,   December 31,   July 31,
    2003
  2002
  2002
    (In thousands)
Change in plan’s benefit obligation
                       
Pension plan’s benefit obligation — beginning of year
  $ 44,302     $ 40,788     $ 33,402  
Service cost
    2,281       779       1,458  
Interest cost
    3,239       1,213       2,448  
Benefits paid
    (3,772 )     (1,110 )     (2,785 )
Actuarial loss
    6,340       2,632       2,361  
Acquisition
    4,172              
Plan amendments
                3,904  
 
   
 
     
 
     
 
 
Pension plan’s benefit obligation — end of year
    56,562       44,302       40,788  
Change in pension plan assets
                       
Fair value of plan assets — beginning of year
    23,526       24,026       25,451  
Actual return (loss) on plan assets
    5,705       (390 )     (3,140 )
Benefits paid
    (3,772 )     (1,110 )     (2,785 )
Employer contributions
    7,700       1,000       4,500  
 
   
 
     
 
     
 
 
Fair value of plan assets — end of year
    33,159       23,526       24,026  
Reconciliation of funded status
                       
Under-funded balance
    (23,403 )     (20,776 )     (16,762 )
Unrecognized prior service cost
    3,535       3,796       3,904  
Unrecognized net loss
    16,139       13,989       10,298  
 
   
 
     
 
     
 
 
Accrued pension liability (net amount recognized)
  $ (3,729 )   $ (2,991 )   $ (2,560 )
 
   
 
     
 
     
 
 
Amounts recognized in consolidated balance sheet
                       
Intangible asset
  $ 3,535     $ 3,796     $ 3,386  
Accrued pension liability
    (7,374 )     (8,534 )     (5,946 )
Accumulated other comprehensive income
    110       1,747        
 
   
 
     
 
     
 
 
Accrued pension liability (net amount recognized)
  $ (3,729 )   $ (2,991 )   $ (2,560 )
 
   
 
     
 
     
 
 

The accumulated benefit obligation was $40,533,000 and $32,060,000 at December 31, 2003 and 2002, respectively, which exceeded the fair value of plan assets.

The weighted average assumptions used to determine end of period benefit obligations:

                         
    December 31,   December 31,   July 31,
    2003
  2002
  2002
Discount rate
    6.25 %     6.75 %     7.25 %
Rate of future compensation increases
    4.25 %     5.00 %     5.00 %

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Net periodic pension expense consisted of the following components:

                                 
    Year Ended
December 31,
  Five Months
Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
    (In thousands)
Service cost — benefit earned during the year
  $ 2,281     $ 779     $ 1,458     $ 1,297  
Interest cost on projected benefit obligations
    3,239       1,213       2,448       2,558  
Expected return on plan assets
    (2,115 )     (843 )     (2,203 )     (2,321 )
Amortization of prior service cost
    261       109              
Amortization of net loss
    600       173              
Amortization of transition asset
                      (115 )
 
   
 
     
 
     
 
     
 
 
Net periodic pension expense
  $ 4,266     $ 1,431     $ 1,703     $ 1,419  
 
   
 
     
 
     
 
     
 
 

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

                                 
    Year Ended
December 31,
  Five Months
Ended
December 31,
  Fiscal Years Ended July 31,
    2003
  2002
  2002
  2001
Discount rate
    7.04 %     7.25 %     7.50 %     7.75 %
Rate of future compensation increases
    4.69 %     5.00 %     5.00 %     5.00 %
Expected long-term rate of return on assets
    8.50 %     8.50 %     8.50 %     8.50 %

The asset allocation for the Company’s retirement plan at year end, by asset category, follows:

                                 
            Percentage of Plan Assets at Year End
    Target   December 31,   December 31,   July 31,
Asset Category
  Allocation 2004
  2003
  2002
  2002
Equity securities
    70 %     61 %     63 %     64 %
Debt Securities
    30 %     39 %     37 %     36 %
 
   
 
     
 
     
 
     
 
 
Total
    100 %     100 %     100 %     100 %
 
   
 
     
 
     
 
     
 
 

The asset allocation at December 31, 2003 reflects a $4,200,000 contribution made in late December 2003. The contribution was held in debt securities until January 2004 when a rebalancing was done to bring assets in line with target allocation.

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

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

The expected long-term rate of returns on Plan Assets is 8.5% and is based on historical investment returns. The assumed long-term rate of return on equity and fixed income investments is 10% and 5% respectively and using the

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Plan’s asset allocation target of 70% equities and 30% fixed income, the overall assumed rate of return on the Plan is 8.5%.

The Company expects to contribute between $2 million to $4 million to the retirement plan in 2004. Benefit payments, which reflect expected future service, are expected to be paid as follows: $3,055,000 in 2004; $2,708,000 in 2005, $3,131,000 in 2006; $4,027,000 in 2007; $4,472,000 in 2008; and $31,953,000 in 2009-2013.

Retirement Restoration Plan: The Company adopted an unfunded retirement restoration plan that provides for additional payments from the Company so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. The Company expensed $408,000 in 2003, $161,000 for the five months ended December 31, 2002, $347,000 in fiscal 2002, and $357,000 in fiscal 2001 in connection with this plan. The accrued liability reflected in the consolidated balance sheet was $2,984,000 at December 31, 2003, $2,186,000 at December 31, 2002 and $2,047,000 at July 31, 2002. As of December 31, 2003, the projected benefit obligation under this plan was $3,510,000.

Defined Contribution Plans: The Company has defined contribution (“401(k)”) plans that cover substantially all employees. Company contributions are based on employee’s compensation and partially match employee contributions. The Company has expensed $1,377,000 in 2003, $472,000 for the five months ended December 31, 2002, $1,106,000 in fiscal 2002, and $1,158,000 in fiscal 2001 in connection with these plans.

Postretirement Medical Plan: The Company has adopted an unfunded postretirement medical plan as part of the voluntary early retirement program offered to eligible employees in fiscal 2000. As part of the early retirement program, the Company agreed to allow retiring employees to continue coverage at a reduced cost under Company group medical plans until normal retirement age. The accrued liability reflected in the consolidated balance sheet was $2,720,000 at December 31, 2003, $2,919,000 at December 31, 2002, and $2,974,000 at July 31, 2002 related to this plan.

Additionally, the Company maintains an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive company paid benefits. Periodic costs under this plan have historically been insignificant. As of December 31, 2003, the total accumulated postretirement benefit obligation under the Company’s postretirement medical plans was $4,807,000.

NOTE 14: Derivative Instruments and Hedging Activities

The Company periodically utilizes petroleum commodity futures contracts to reduce its exposure to the price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. The Company has also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. The Company regularly utilizes 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. The Company believes 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, the Company 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 the Company from the risk that the refined product margins with respect to the hedged gasoline sales would decline. 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 $161,000 for the year ended July 31, 2001, which was included in cost of products sold.

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During the fiscal year ended July 31, 2001, the Company 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, included in comprehensive income, was a loss of $2.1 million, as the values of the outstanding hedges were marked to the current fair value. In fiscal 2002, the Company 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, the Company 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 the Company from the risk that the refinery margin would decline with respect to the hedged crude oil and refined products. To effect the hedges the Company entered into gasoline and crude oil futures transactions. Gains and losses reported in accumulated other comprehensive income were reclassified into income when the forecasted transactions occurred. During the five months ended December 31, 2002, the Company marked the value of the outstanding hedges to fair value in accordance with SFAS 133 and included $47,000 of income in comprehensive income. In March 2003, as the forecasted transactions occurred, the Company reclassified $108,000 of actual losses from comprehensive income to cost of sales. The ineffective portion of the hedges resulted in a $32,000 gain that was also included in cost of sales.

In October 2003, the Company 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 $71,000 and were recorded into refining operating costs. At December 31, 2003, included in comprehensive income, was a gain of $599,000, 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.

NOTE 15: Lease Commitments

The Company leases certain facilities, pipelines and equipment under operating leases, most of which contain renewal options. At December 31, 2003, the minimum future rental commitments under operating leases having noncancellable lease terms in excess of one year total in the aggregate $20,581,000, of which the following amounts are payable over the next five years: 2004 — $6,072,000; 2005 — $5,951,000; 2006 — $5,551,000; 2007 — $2,733,000 and 2008 — $87,000. Rental expense charged to operations was $6,762,000 in 2003, $2,891,000 in the five months ended December 31, 2002, $6,894,000 in fiscal 2002, and $6,359,000 in fiscal 2001.

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NOTE 16: Contingencies

In November 2002, the Company settled by agreement litigation brought in August 1998 by Longhorn Partners Pipeline, L.P. (“Longhorn Partners”) against the Company in a state court in El Paso, Texas and litigation brought in August 2002 by the Company against Longhorn Partners and related parties in a state court in Carlsbad, New Mexico. Under the settlement agreement, which was developed in voluntary mediation, in November 2002, the Company paid $25 million to Longhorn Partners as a prepayment for the transportation of 7,000 barrels per day of refined products from the Gulf Coast to El Paso for a period of up to 6 years from the date of the Longhorn Pipeline’s start-up. Longhorn Partners has also issued to the Company an unsecured $25 million promissory note, subordinated to certain other indebtedness, that would become payable with interest in the event that the Longhorn Pipeline does not begin operations by July 1, 2004, or to the extent Longhorn Partners is unable to provide the Company the full amount of the agreed transportation services. In the consolidated balance sheet at December 31, 2003, the $25 million settlement is reflected in Assets as “Other assets – Prepaid transportation.”

Petitions for review are pending before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit Appeals Court”) with respect to rulings by the Federal Energy Regulatory Commission (“FERC”) in proceedings brought by the Company and other parties against Kinder Morgan’s SFPP, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. The Company is 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 are the subject of proceedings in the D.C. Circuit Appeals Court resulted in reparations payments to the Company in 2003 totaling approximately $15.3 million relating principally to the period from 1993 through July 2000. The D.C. Circuit Appeals Court heard oral argument in November 2003 on issues relating to reparations to the Company and other shippers. As of the date of this report, the D.C. Circuit Appeals Court has not issued an opinion in the case. The opinion of the D.C. Circuit Court of Appeals could result in a determination that the reparations actually due to the Company in this matter are less than or more than the $15.3 million received by the Company in 2003. In the event that as a result of these proceedings the actual reparations amount due to the Company is determined to be less than the amounts received by the Company in 2003, part or all of the amounts received by the Company would have to be refunded. Although it is not possible at the date of this report to predict the outcome of the pending proceedings on this matter in the D.C. Circuit Appeals Court, the Company believes that any amount of reparations payments which may be required to be refunded as a result of these proceedings would not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

In December 2001, following discussions initiated by the Company, the Company entered into a Consent Decree (the “Consent Decree”) with the Environmental Protection Agency (“EPA”), the New Mexico Environment Department and the Montana Department of Environmental Quality with respect to a global settlement of issues concerning the application of air quality requirements to past and future operations of the Company’s refineries. The Consent Decree was entered by the federal court in New Mexico in March 2002 and requires the Company to make investments at the Company’s New Mexico and Montana refineries for the installation of certain state of the art pollution control equipment currently expected to total approximately $15 million over a period expected to end in 2009, of which approximately $8 million has been expended. The Consent Decree also provided for payment by the Company of penalties to Federal, New Mexico and Montana regulatory authorities in the total amount of $750,000, which were paid in fiscal 2002.

On August 20, 2003, Frontier Oil Corporation (“Frontier”) filed a lawsuit in the Delaware Court of Chancery seeking declaratory relief and damages based on allegations that the Company repudiated its obligations and breached an implied covenant of good faith and fair dealing under an agreement (the “Frontier Merger Agreement”) announced in late March 2003 under which Frontier and the Company were to be combined. On August 21, 2003, the Company formally notified Frontier of the Company’s 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 Frontier 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, the Company filed in the Delaware Court of Chancery its Answer and Counterclaims seeking declaratory judgments that the Company had not repudiated the Frontier Merger

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Agreement, that Frontier had repudiated the Frontier Merger Agreement, that Frontier had breached certain representations made by Frontier in the Frontier Merger Agreement, that the Company’s obligations under the Frontier Merger Agreement were and are excused and that the Company may terminate the Frontier Merger Agreement without liability, and seeking damages as well as costs and attorneys’ fees. To the date of this report, the Company has not taken any actions, beyond the sending of the August 21, 2003 notification with respect to the Beverly Hills High School matter, under the various provisions of the Frontier Merger Agreement relating to the Company’s rights to terminate the Frontier Merger Agreement. Frontier was permitted by the court to amend its Complaint shortly before the beginning of the trial to assert that the Company’s actions entitle Frontier to payment of a breakup fee of $16 million plus certain legal expenses. The trial with respect to Frontier’s amended Complaint and the Company’s Answer and Counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. Following submission of post-trial briefs and oral argument, a decision is expected to be announced within several months after completion of the trial. Although it is not possible at the date of this report to predict the outcome of this litigation, the Company believes that the claims made by Frontier in the litigation are wholly without merit and that the Company’s counterclaims are well founded.

The Company is a party to various other litigation and proceedings which it believes, based on advice of counsel, will not have a materially adverse impact on the Company’s financial condition, results of operations or cash flows.

NOTE 17: Segment Information

The Company has two major business segments: Refining and Pipeline Transportation. The Refining segment involves the refining of crude oil and wholesale marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes the Company’s Navajo Refinery, Woods Cross Refinery and Montana Refinery. The Woods Cross Refinery was acquired in June 2003. The petroleum products produced by the Refining segment are marketed in the southwestern United States, Utah, Wyoming, Montana and northern Mexico. Certain pipelines and terminals operate in conjunction with the Refining segment as part of the supply and distribution networks of the refineries. The Refining segment also includes the equity earnings from the Company’s 49% (50% prior to January 1, 2002) interest in NK Asphalt Partners, which manufactures and markets asphalt and asphalt products in Arizona and New Mexico. The pipeline transportation segment currently includes approximately 500 miles of the Company’s pipeline assets in Texas and New Mexico. Revenues from the Pipeline Transportation segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations. Pipeline Transportation segment revenues do not include any amount relating to pipeline transportation services provided for the Company’s refining operations. The Pipeline Transportation segment also includes the earnings from the Company’s 70% (25% prior to June 30, 2003) interest in Rio Grande Pipeline Company, which provides petroleum products transportation. Operations of the Company that are not included in the two reportable segments are included in Corporate and other, which includes costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses and interest charges, as well as a small-scale oil and gas exploration and production program, and a small equity investment in retail gasoline stations and convenience stores. Additionally included in Corporate and other during 2003 were the retail stations purchased from ConocoPhillips as part of the Woods Cross Refinery acquisition that were subsequently sold.

The accounting policies for the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on earnings and cash flows. The Company’s reportable segments are strategic business units that offer different products and services.

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                    Total for        
            Pipeline   Reportable   Corporate   Consolidated
    Refining
  Transportation
  Segments
  & Other
  Total
    (In thousands)
Year Ended December 31, 2003
                                       
Sales and other revenues
  $ 1,373,406     $ 21,030     $ 1,394,436     $ 8,808     $ 1,403,244  
Depreciation and amortization
  $ 31,889     $ 2,488     $ 34,377     $ 1,898     $ 36,275  
Income (loss) from operations
  $ 53,854     $ 29,110     $ 82,964     $ (22,897 )   $ 60,067  
Income (loss) before income taxes
  $ 69,742     $ 28,891     $ 98,633     $ (24,274 )   $ 74,359  
Total assets
  $ 627,829     $ 54,303     $ 682,132     $ 26,760     $ 708,892  
Five Months Ended December 31, 2002
                                       
Sales and other revenues
  $ 439,788     $ 8,245     $ 448,033     $ 604     $ 448,637  
Depreciation and amortization
  $ 10,264     $ 600     $ 10,864     $ 862     $ 11,726  
Income (loss) from operations
  $ 8,017     $ 4,800     $ 12,817     $ (4,427 )   $ 8,390  
Income (loss) before income taxes
  $ 7,498     $ 5,728     $ 13,226     $ (4,709 )   $ 8,517  
Total assets
  $ 458,339     $ 20,458     $ 478,797     $ 36,996     $ 515,793  
Year Ended July 31, 2002
                                       
Sales and other revenues
  $ 868,730     $ 18,588     $ 887,318     $ 1,588     $ 888,906  
Depreciation and amortization
  $ 24,789     $ 1,394     $ 26,183     $ 1,516     $ 27,699  
Income (loss) from operations
  $ 42,725     $ 10,621     $ 53,346     $ (10,300 )   $ 43,046  
Income (loss) before income taxes
  $ 48,597     $ 12,220     $ 60,817     $ (9,921 )   $ 50,896  
Total assets
  $ 391,635     $ 22,109     $ 413,744     $ 88,562     $ 502,306  
Year Ended July 31, 2001
                                       
Sales and other revenues
  $ 1,120,248     $ 18,454     $ 1,138,702     $ 3,428     $ 1,142,130  
Depreciation and amortization
  $ 24,818     $ 1,487     $ 26,305     $ 1,022     $ 27,327  
Income (loss) from operations
  $ 116,218     $ 10,243     $ 126,461     $ (8,554 )   $ 117,907  
Income (loss) before income taxes
  $ 119,563     $ 12,551     $ 132,114     $ (10,219 )   $ 121,895  
Total assets
  $ 384,844     $ 22,516     $ 407,360     $ 83,069     $ 490,429  

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 18: Significant Customers

All revenues were domestic revenues, except for sales of gasoline and diesel fuel for export into Mexico by the Refining segment. The export sales were to an affiliate of PEMEX (the government-owned energy company of Mexico) and accounted for approximately $57,000,000 (4%) of the Company’s revenues for 2003, $26,000,000 (6%) of revenues for the five months ended December 31, 2002, 45,000,000 (5%) of revenues for fiscal 2002, and $97,000,000 (8%) of revenues for fiscal 2001. Sales of military jet fuel to the United States Government by the Refining segment accounted for approximately $85,000,000 (6%) of the Company’s revenues for 2003, $40,000,000 (9%) of revenues for the five months ended December 31, 2002, $78,000,000 (9%) of revenues for fiscal 2002, and $113,000,000 (10%) of revenues for fiscal 2001. In addition to the United States Government and PEMEX, other significant sales by the Refining segment were made to two petroleum companies, one of which accounted for approximately $163,000,000 (12%) of the Company’s revenues in 2003, $67,000,000 (15%) of revenues for the five months ended December 31, 2002, $131,000,000 (15%) of revenues in fiscal 2002, and $184,000,000 (16%) of the revenues in fiscal 2001, and the other accounted for $162,000,000 (12%) of the Company’s revenues in 2003, $52,000,000 (12%) of revenues for the five months ended December 31, 2002, $116,000,000 (13%) of revenues in fiscal 2002, $147,000,000 (13%) of revenues for fiscal 2001.

NOTE 19: Other Income

On March 4, 2003, the Company sold its 400-mile Iatan crude oil gathering system located in West Texas to Plains All-American Pipeline, L.P. for $24 million in cash, and agreed to transport crude oil purchased in West Texas on the Iatan system at an agreed upon tariff for six and a half years. The Iatan system, while profitable, was not considered central to the Company’s refining operations. The sale resulted in a pre-tax gain to the Company of $16,207,000. The proceeds from the sale increased the Company’s cash resources available for investment in its core refining operations, including its acquisition of the Woods Cross Refinery. The net gain on sale of assets of $15,814,000 on the statement of income was reduced by the loss on sale of retail assets of $393,000 described in Note 21.

In April 2003 and June 2003, the Company received reparation payments totaling approximately $15,330,000 from SFPP. The payments were for claims brought by the Company and other parties before the FERC relating to tariffs of common carrier pipelines owned and operated by SFPP for shipments of refined products over several years from El Paso, Texas to Tucson and Phoenix, Arizona from points in California to points in Arizona. The final decision of the FERC is subject to judicial review. See Note 16 for additional information.

In fiscal year ended July 31, 2002, the Company realized a $1,522,000  gain on the sale of marketable equity securities held for investment.

In fiscal year ended July 31, 2001, the Company agreed to a settlement of all claims relating to the Company’s purchase of certain pipeline assets in fiscal 1998. The Company recognized $1,153,000 as income in fiscal 2001 relating to this settlement.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 20: Refinery and Retail Assets Acquisition

On June 1, 2003, the Company acquired from ConocoPhillips the Woods Cross Refinery, located near Salt Lake City, Utah, and related assets, including a refined products terminal in Spokane, WA, and a 50% ownership interest in refined products terminals in Boise and Burley, Idaho for an agreed price of $25 million plus inventory less obligations assumed. The Woods Cross Refinery has a crude oil capacity of 25,000 BPD and has operated at close to capacity over the last three years. 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 by the Company in August 2003, see Note 21), and a 10-year exclusive license to market fuels under the Phillips brand in the states of Utah, Wyoming, Idaho and Montana. The total cash purchase price, including expenses and the deposit made in 2002, was $58.3 million. In accounting for the purchase, the Company recorded inventory of $35.5 million, property, plant and equipment of $25.6 million, intangible assets of $1.6 million, and recorded a $4.4 million liability, principally for pension obligations.

NOTE 21: Sale of Woods Cross Retail Assets

In August 2003, the Company sold its retail assets located in Utah and Wyoming for $7 million, less the Company’s prorated share of property taxes and certain transaction expenses, plus $1.8 million for inventories, resulting in net cash proceeds of $8.5 million. The sale resulted in a pre-tax loss for the Company of approximately $393,000, due mainly to the transaction expenses. The asset package included twenty-five operating retail sites and three closed properties that the Company acquired from ConocoPhillips on June 1, 2003 in the acquisition of the Woods Cross Refinery. The Company will continue to supply the stations with fuel from its Woods Cross Refinery.

NOTE 22: Quarterly Information (Unaudited)

                                         
    First   Second   Third   Fourth    
    Quarter
  Quarter
  Quarter (1)
  Quarter
  Year
    (In thousands, except share data)
Year Ended December 31, 2003
                                       
Sales and other revenues
  $ 314,912     $ 323,287     $ 415,257     $ 349,788     $ 1,403,244  
Operating costs and expenses
  $ 308,048     $ 313,514     $ 386,414     $ 351,015     $ 1,358,991  
Income (loss) from operations
  $ 24,550     $ 8,294     $ 28,450     $ (1,227 )   $ 60,067  
Income (loss) before income taxes
  $ 23,528     $ 24,295     $ 28,654     $ (2,118 )   $ 74,359  
Net income (loss)
  $ 14,433     $ 15,151     $ 17,550     $ (1,081 )   $ 46,053  
Net income (loss) per common share — basic
  $ 0.93     $ 0.98     $ 1.13     $ (0.07 )   $ 2.97  
Net income (loss) per common share — diluted
  $ 0.91     $ 0.94     $ 1.09     $ (0.07 )   $ 2.88  
Dividends per common share
  $ 0.11     $ 0.11     $ 0.11     $ 0.11     $ 0.44  
Average number of shares of common stock outstanding
                                       
Basic
    15,500       15,503       15,506       15,511       15,505  
Diluted
    15,948       16,048       16,029       15,511       16,016  

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                         
    Two Months   Three Months    
    Aug-Sept
  Oct - Dec
  Five Months
    (In thousands, except share data)
Transition Period Ended December 31, 2002
                       
Sales and other revenues
  $ 178,520     $ 270,117     $ 448,637  
Operating costs and expenses
  $ 177,436     $ 262,811     $ 440,247  
Income from operations
  $ 1,084     $ 7,306     $ 8,390  
Income before income taxes
  $ 2,451     $ 6,066     $ 8,517  
Net income
  $ 1,497     $ 3,906       5,403  
Net income per common share — basic
  $ 0.10     $ 0.25       0.35  
Net income per common share — diluted
  $ 0.09     $ 0.25       0.34  
Dividends per common share
  $     $ 0.11       0.11  
Average number of shares of common stock outstanding
                       
Basic
    15,526       15,510       15,516  
Diluted
    15,888       15,915       15,902  
                                         
    First   Second   Third   Fourth    
    Quarter
  Quarter
  Quarter
  Quarter
  Year
    (In thousands, except share data)
Year Ended July 31, 2002
                                       
Sales and other revenues
  $ 257,947     $ 166,754     $ 210,327     $ 253,878     $ 888,906  
Operating costs and expenses
  $ 228,890     $ 169,473     $ 201,685     $ 245,812     $ 845,860  
Income (loss) from operations
  $ 29,057     $ (2,719 )   $ 8,642     $ 8,066     $ 43,046  
Income (loss) before income taxes
  $ 33,069     $ (792 )   $ 9,808     $ 8,811     $ 50,896  
Net income (loss)
  $ 20,222     $ (485 )   $ 6,199     $ 6,093     $ 32,029  
Net income (loss) per common share — basic
  $ 1.30     $ (0.03 )   $ 0.40     $ 0.39     $ 2.06  
Net income (loss) per common share — diluted
  $ 1.27     $ (0.03 )   $ 0.39     $ 0.38     $ 2.01  
Dividends per common share
  $ 0.10     $ 0.10     $ 0.10     $ 0.11     $ 0.41  
Average number of shares of common stock outstanding Basic
    15,508       15,559       15,581       15,593       15,560  
Diluted
    15,944       15,996       16,016       15,947       15,971  

(1)   In the Form 10-Q for the third quarter ended September 30, 2003, the Company accounted for its investment in the Rio Grande Pipeline Company on the equity method. Effective at December 31, 2003, the Company consolidated its interest in Rio Grande effective as of June 30, 2003. The effect on the third quarter of 2003 was to increase revenues by $3.1 million, operating costs by $2.4 million and decrease other income by $.7 million.

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

The Company has had no change in, or disagreement with, its independent certified public accountants on matters involving accounting and financial disclosure.

Item 9A. Controls and Procedures

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

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

PART III

Item 10. Directors and Executive Officers of the Registrant

The information required by Items 401, 405 and 406 of Regulation S-K in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on May 13, 2004 and is incorporated herein by reference.

Item 11. Executive Compensation

The information required by Item 402 of Regulation S-K in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on May 13, 2004 and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on May 13, 2004 and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

The information required by Item 404 of Regulation S-K in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on May 13, 2004 and is incorporated herein by reference.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Item 14. Principal Accountant Fees and Services

The information required by Item 9(e) of Schedule 14A in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on May 13, 2004 and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) Documents filed as part of this report

     (1) Index to Consolidated Financial Statements

         
    Page in
    Form 10-K
Report of Independent Auditors
    47  
Consolidated Balance Sheet at December 31, 2003 and 2002, and July 31, 2002
    48  
Consolidated Statement of Income for the years ended December 31, 2003 and 2002 (unaudited), five months ended December 31, 2002, and years ended July 31, 2002 and 2001
    49  
Consolidated Statement of Cash Flows for the years ended December 31, 2003 and 2002 (unaudited), five months ended December 31, 2002, and years ended July 31, 2002 and 2001
    50  
Consolidated Statement of Stockholders’ Equity for the year ended December 31, 2003, five months ended December 31, 2002, and years ended July 31, 2001 and 2000
    51  
Consolidated Statement of Comprehensive Income for the years ended December 31, 2003 and 2002 (unaudited), five months ended December 31, 2002, and years ended July 31, 2002 and 2001
    52  
Notes to Consolidated Financial Statements
    53  

     (2) Index to Consolidated Financial Statement Schedules

All schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

     (3) Exhibits

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See Index to Exhibits on pages 83 to 86.

     (b) Reports on Form 8-K

On November 14, 2003, a Current Report on Form 8-K was furnished for Item 12 Results of Operations and Financial Condition concerning the release of the Company’s earnings for the third quarter of 2003.

On November 19, 2003, a Current Report on Form 8-K was furnished for Item 9 Regulation FD disclosure concerning a presentation by senior management of the Company to analysts in New York City.

On November 25, 2003, a Current Report on Form 8-K was filed under Item 5 Other Events concerning the trial in the pending litigation between the Company and Frontier Oil Corporation.

On January 16, 2004, a Current Report on Form 8-K was filed under Item 5 Other Events concerning the trial in the pending litigation between the Company and Frontier Oil Corporation.

On January 22, 2004, a Current Report on Form 8-K was filed under Item 5 Other Events concerning the Company adding two senior executives.

On February 20, 2004, a Current Report on Form 8-K was furnished for Item 12 Results of Operations and Financial Condition concerning the release of the Company’s earnings for the fourth quarter of 2003.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

         
  HOLLY CORPORATION
(Registrant)
 
 
  /s/ Lamar Norsworthy    
  Lamar Norsworthy   
  Chairman of the Board and Chief Executive Officer   
 

Date: March 10, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and as of the date indicated.

         
Signature
  Capacity
  Date
/s/ Lamar Norsworthy

Lamar Norsworthy
  Chairman of Board of Directors
and Chief Executive Officer
of the Company
  March 10, 2004
/s/ Matthew P. Clifton

Matthew P. Clifton
  President and Director   March 10, 2004
/s/ Scott C. Surplus

Scott C. Surplus
  Vice President and Controller
(Principal Accounting Officer)
  March 10, 2004
/s/ Stephen J. McDonnell

Stephen J. McDonnell
  Vice President and Chief
Financial Officer
(Principal Financial Officer)
  March 10, 2004

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Signature
  Capacity
  Date
/s/ W. John Glancy

W. John Glancy
  Senior Vice President, General Counsel,
Secretary and Director
  March 10, 2004
/s/ William J. Gray

William J. Gray
  Director   March 10, 2004
/s/ Marcus R. Hickerson

Marcus R. Hickerson
  Director   March 10, 2004
/s/ Robert G. McKenzie

Robert G. McKenzie
  Director   March 10, 2004
/s/ Thomas K. Matthews, II

Thomas K. Matthews, II
  Director   March 10, 2004
/s/ Jack P. Reid

Jack P. Reid
  Director   March 10, 2004
/s/ Paul T. Stoffel

Paul T. Stoffel
  Director   March 10, 2004

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HOLLY CORPORATION

INDEX TO EXHIBITS

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

     
Exhibit    
Number
  Description
 3.1
  Restated Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3(a), of Amendment No. 1 dated December 13, 1988 to Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1988, File No. 1-3876).
 
   
 3.2 
  By-Laws of Holly Corporation as amended and restated March 9, 2001 and Amendment to By-Laws dated September 30, 2003 (incorporated by reference to Exhibits 3.2.1 and 3.2.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2003, File No. 1-3876).
 
   
10.1
  7.62% Series C Senior Note of Holly Corporation, dated as of November 21, 1995, to John Hancock Mutual Life Insurance Company, with schedule attached thereto of five other substantially identical Notes which differ only in the respects set forth in such schedule (incorporated by reference to Exhibit 4.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended October 31, 1995, File No. 1-3876).
 
   
10.2
  Series D Senior Note of Holly Corporation, dated as of November 21, 1995, to John Hancock Mutual Life Insurance Company, with schedule attached thereto of three other substantially identical Notes which differ only in the respects set forth in such schedule (incorporated by reference to Exhibit 4.5 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended October 31, 1995, File No. 1-3876).
 
   
10.3
  Note Agreement of Holly Corporation, dated as of November 15, 1995, to John Hancock Mutual Life Insurance Company, with schedule attached thereto of five other substantially identical Note Agreements which differ only in the respects set forth in such schedule (incorporated by reference to Exhibit 4.6 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended October 31, 1995, File No. 1-3876).
 
   
10.4
  Guaranty, dated as of November 15, 1995, of Navajo Refining Company, Navajo Pipeline Company, Lea Refining Company, Navajo Holdings, Inc., Navajo Western Asphalt Company and Navajo Crude Oil Marketing Company in favor of John Hancock Mutual Life Insurance Company, John Hancock Variable Life Insurance Company, Alexander Hamilton Life Insurance Company of America, The Penn Mutual Life Insurance Company, AIG Life Insurance Company and Pan-American Life Insurance Company (incorporated by reference to Exhibit 4.7 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended October 31, 1995, File No. 1-3876).

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Exhibit    
Number
  Description
10.5 
  Guaranty, dated as of October 10, 1997, of Navajo Corp., Navajo Southern, Inc., Navajo Crude Oil Purchasing, Inc. and Lorefco, Inc in favor of the Holders to the Note Agreements dated as of November 15, 1995 (incorporated by reference to Exhibit 4.29 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1997, File No. 1-3876).
 
   
10.6 
  Letter of Consent, Waiver and Amendment, dated as of November 15, 1995, among Holly Corporation, and New York Life Insurance Company, John Hancock Mutual Life Insurance Company, John Hancock Variable Life Insurance Company, Confederation Life Insurance Company, The Penn Insurance and Annuity Company, The Penn Mutual Life Insurance Company, The Manhattan Life Insurance Company, The Union Central Life Insurance Company, Safeco Life Insurance Company, American International Life Assurance Company of New York, Pan-American Life Insurance Company and Jefferson-Pilot Life Insurance Company (incorporated by reference to Exhibit 4.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended October 31, 1995, File No. 1-3876).
 
   
10.7 
  The First Amendment to Note Agreement, dated as of December 31, 2001, by Holly Corporation, John Hancock Mutual Life Insurance Company and each other Purchaser to that Note Agreement, dated as of November 15, 1995, between the Company, John Hancock and the Other Purchasers (incorporated by reference to Exhibit 10.7 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2001, File No. 1-3876).
 
   
10.8 
  $100,000,000 Amended and Restated Credit and Reimbursement Agreement, dated as of April 14, 2000, among Holly Corporation, Navajo Refining Company, Black Eagle, Inc., Navajo Corp., Navajo Southern, Inc., Navajo Northern, Inc., Lorefco, Inc., Navajo Crude Oil Purchasing, Inc., Navajo Holdings, Inc., Holly Petroleum, Inc., Navajo Pipeline Co., Lea Refining Company, Navajo Western Asphalt Company and Montana Refining Company, A Partnership, as Borrowers and Guarantors, the Banks listed herein, Canadian Imperial Bank of Commerce, as Administrative Agent, CIBC Inc., as Collateral Agent, Fleet National Bank, as Collateral Monitor and Documentation Agent and CIBC World Markets Corp., as sole Lead Arranger and Bookrunner, with schedules and exhibits (incorporated by reference to Exhibit 4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended April 30, 2000, File No. 1-3876).
 
   
10.9 
  Amendment No. 1 dated as of July 14, 2000, of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 4.13 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2000, File No. 1-3876).
 
   
10.10
  Agreement of Increased Commitment as of August 2, 2000, of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 4.14 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2000, File No. 1-3876).
 
   
10.11
  Letter Agreement as of August 2, 2000, with respect to the Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 4.15 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2000, File No. 1-3876).

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Exhibit    
Number
  Description
10.12 
  Amendment No. 2 dated as of April 4, 2001 of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended April 30, 2001, File No. 1-3876).
 
   
10.13 
  Amendment No. 3 dated as of August 7, 2001 of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 10.13 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2001, File No. 1-3876).
 
   
10.14 
  Amendment No. 4 dated as of September 26, 2001 of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 10.14 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2001, File No. 1-3876).
 
   
10.15*
  Holly Corporation Stock Option Plan — As adopted at the Annual Meeting of Stockholders of Holly Corporation on December 13, 1990 (incorporated by reference to Exhibit 4(i) of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1991, File No. 1-3876).
 
   
10.16*
  Holly Corporation Long-Term Incentive Compensation Plan as Amended and Restated (Formerly Designed the Holly Corporation 2000 Stock Option Plan) - - As approved at the Annual Meeting of Stockholders of Holly Corporation on December 12, 2002 (incorporated by reference to Exhibit 10 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended October 31, 2002, File No. 1-3876).
 
   
10.17*
  Supplemental Payment Agreement, dated as of July 8, 1993, between Lamar Norsworthy and Holly Corporation (incorporated by reference to Exhibit 10(a) of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1993, File No. 1-3876).
 
   
10.18*
  Holly Corporation –Supplemental Payment Agreement for 2001 Service as Director (incorporated by reference to Exhibit 10.19 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876).
 
   
10.19*
  Holly Corporation –Supplemental Payment Agreement for 2002 Service as Director (incorporated by reference to Exhibit 10.20 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876).
 
   
10.20 
  Amendment No. 5 dated May 6, 2002, of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 10.21 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876).
 
   
10.21 
  Amendment No. 6 dated August 6, 2002, of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 10.22 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876).
 
   
10.22 
  Amendment No. 7 dated May 15, 2003, of Amended and Restated Credit Agreement dated as of April 14, 2000 (incorporated by reference to Exhibit 99.2 of Registrant’s Form 8-K dated June 1, 2003, File No. 1-3876).
 
   
10.23*
  Holly Corporation – Supplemental Payment Agreement for 2003 Service as Director (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-3876).
 
   
10.24 
  Asset Purchase and Sale Agreement between Phillips Petroleum Company as Seller and Holly Corporation as Buyer Dated as of December 20, 2002 (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-3876).

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21.1
  Subsidiaries of Registrant
 
   
23.1
  Consent of Independent Auditors
 
   
31.1
  Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2
  Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
*
  Constitute management contracts or compensatory plans or arrangements.
exv21w1
 

EXHIBIT 21.1

HOLLY CORPORATION

SUBSIDIARIES OF REGISTRANT

     
    State of
    Incorporation
Name of Entity
  or Organization
Black Eagle, Inc.
  Delaware
Hollycorp Aviation, L.L.C.
  Delaware
Holly Refining & Marketing Company
  Delaware
Holly Logistic Services, L.L.C.
  Delaware
Holly Petroleum, Inc.
  Delaware
Holly Refining Communications, Inc.
  Delaware
Holly Utah Holdings, Inc.
  Delaware
Lea Refining Company
  Delaware
Lorefco, Inc.
  Delaware
Montana Refining Company, a Partnership (1)
  Montana
Montana Retail Corporation
  Delaware
Navajo Crude Oil Purchasing, Inc.
  New Mexico
Navajo Holdings, Inc.
  New Mexico
Navajo Northern, Inc.
  Nevada
Navajo Pipeline Co., L.P. (2)
  Delaware
Navajo Pipeline GP, L.L.C.
  Delaware
Navajo Pipeline LP, L.L.C.
  Delaware
Navajo Refining Company, L.P. (3)
  Delaware
Navajo Refining GP, L.L.C.
  Delaware
Navajo Refining LP, L.L.C.
  Delaware
Navajo Southern, Inc.
  Delaware
Navajo Western Asphalt Company
  New Mexico
Rio Grande Pipeline Company
  Texas
Woods Cross Refining Company, L.L.C. (4)
  Delaware

(1)   Montana Refining Company, a Partnership also does business as Montana Refining Company.
 
(2)   Navajo Pipeline Co., L.P. also does business as Navajo Pipeline Co.
 
(3)   Navajo Refining Company, L.P. also does business as Navajo Refining Company.
 
(4)   Woods Cross Refining Company, L.L.C. does business as Holly Refining & Marketing Company.

 

exv23w1
 

EXHIBIT 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in the Registration Statements (Form S-8 Nos. 2-74856 and 333-54612) pertaining to the Holly Corporation Stock Option Plan and the Holly Corporation Long-Term Incentive Compensation Plan and in the related Prospectuses of our report dated February 19, 2004 with respect to the consolidated financial statements of Holly Corporation included in this Annual Report (Form 10-K) for the year ended December 31, 2003.

ERNST & YOUNG LLP

Dallas, Texas
March 10, 2004

 

exv31w1
 

Exhibit 31.1

CERTIFICATION

I, Lamar Norsworthy, Chairman of the Board and Chief Executive Officer of Holly Corporation, certify that:

1. I have reviewed this annual report on Form 10-K of Holly Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by this annual report on Form 10-K that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

     
Date: March 10, 2004
  /s/ C. Lamar Norsworthy, III
 
 
  C. Lamar Norsworthy, III
Chairman of the Board and Chief Executive Officer

 

exv31w2
 

Exhibit 31.2

CERTIFICATION

I, Stephen J. McDonnell, Vice President and Chief Financial Officer of Holly Corporation, certify that:

1. I have reviewed this annual report on Form 10-K of Holly Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by this annual report on Form 10-K that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

     
Date: March 10, 2004
  /s/ Stephen J. McDonnell
 
 
  Stephen J. McDonnell
Vice President and Chief Financial Officer

 

exv32w1
 

EXHIBIT 32.1

CERTIFICATION OF CHIEF EXECUTIVE

OFFICER OF HOLLY CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-K for the period ending December 31, 2003 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, C. Lamar Norsworthy, III, Chief Executive Officer of Holly Corporation (the “Company”) hereby certify that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

     
Date: March 10, 2004
  /s/ C. Lamar Norsworthy, III
 
 
  C. Lamar Norsworthy, III
Chief Executive Officer

 

exv32w2
 

EXHIBIT 32.2

CERTIFICATION OF CHIEF FINANCIAL

OFFICER OF HOLLY CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-K for the period ending December 31, 2003 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen J. McDonnell, Chief Financial Officer of Holly Corporation (the “Company”) hereby certify that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

     
Date: March 10, 2004
  /s/ Stephen J. McDonnell
 
 
  Stephen J. McDonnell
Chief Financial Officer