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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
     
þ   Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2008
OR
     
o   Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from                      to                     
Commission File Number 1-3876
HOLLY CORPORATION
(Exact name of registrant as specified in its charter)
     
Delaware   75-1056913
(State or other jurisdiction of   (I.R.S Employer
incorporation or organization)   Identification No.)
     
100 Crescent Court, Suite 1600, Dallas, Texas   75201-6915
(Address of principle executive offices)   (Zip Code)
Registrant’s telephone number, including area code (214) 871-3555
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.01 par value registered on the New York Stock Exchange.
Securities registered pursuant to 12(g) of the Act:
None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act). (Check one):
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
On June 30, 2008 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $1,494 million. (This is not to be deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.)
50,069,998 shares of Common Stock, par value $.01 per share, were outstanding on February 6, 2009.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 14, 2009, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2008, are incorporated by reference in Part III.
 
 

 


 

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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, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. These statements are based on management’s belief and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors including, but not limited to:
    risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum products in our markets;
 
    the demand for and supply of crude oil and refined products;
 
    the spread between market prices for refined products and market prices for crude oil;
 
    the possibility of constraints on the transportation of refined products;
 
    the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines;
 
    effects of governmental regulations and policies;
 
    the availability and cost of our financing;
 
    the effectiveness of our capital investments and marketing strategies;
 
    our efficiency in carrying out construction projects;
 
    our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate any future acquired operations;
 
    the possibility of terrorist attacks and the consequences of any such attacks;
 
    general economic conditions; and
 
    other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.
Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation in conjunction with the forward-looking statements included in this Form 10-K that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A and in conjunction with the discussion in this Form 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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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 calendar day of crude oil or petroleum products.
     “BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum products.
     “Black wax crude oil” is a low sulfur, low gravity crude oil produced in the Uintah Basin in Eastern Utah that has certain characteristics that require specific facilities to transport, store and refine into transportation fuels.
     “Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is the primary source of hydrogen for the refinery.
     “Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules.
     “Crude distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing slightly above atmospheric pressure the vapor back to liquid in order to purify, fractionate or form the desired products.
     “Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline.
     “FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.
     “Hydrocracker” means a refinery unit that breaks down large complex hydrocarbon molecules into smaller more useful ones using a fixed bed of catalyst at high pressure and temperature with hydrogen.
     “Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and a catalyst at relatively high temperatures.
     “Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization processes.
     “HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.
     “Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.
     “LPG” means liquid petroleum gases.
     “LSG,” or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.
     “MMBtu” or one million British thermal units, means for each unit, the amount of heat required to raise one pound of water one degree Fahrenheit at one atmosphere pressure.
     “MMSCFD” means one million standard cubic feet per day.

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     “MTBE” means methyl tertiary butyl ether, a high octane gasoline blend stock that is used to make various grades of gasoline.
     “Natural gasoline” means a low octane gasoline blend stock that is purchased and used to blend with other high octane stocks produced to make various grades of gasoline.
     “PPM” means parts-per-million.
     “Refinery gross margin” means the difference between average net sales price and average costs of products per barrel of produced refined products. This does not include the associated depreciation and amortization costs.
     “Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks while producing hydrogen in the process.
     “ROSE”, or “Solvent deasphalter / residuum oil supercritical extraction,” means a refinery unit that uses a light hydrocarbon like propane or butane to extract non-asphaltene heavy oils from asphalt or atmospheric reduced crude. These deasphalted oils are then further converted to gasoline and diesel in the FCC process. The remaining asphaltenes are either sold, blended to fuel oil or blended with other asphalt as a hardener.
     “Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet crude oil” means crude oil containing quantities of sulfur equal to or less than 0.4 percent by weight.
     “ULSD,” or ultra low sulfur diesel, means diesel fuel that contains less than 15 PPM of total sulfur.
     “Vacuum distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing below atmospheric pressure the vapor back to liquid in order to purify, fractionate or form the desired products.

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INDEX TO DEFINED TERMS AND NAMES
The following other terms and names that appear in this form 10-K are defined on the following pages:
         
    Page
    Reference
2004 ACT
    49  
2005 ACT
    49  
Amended NOV
    32  
AOC
    32  
CAA
    20  
CERCLA
    21  
Connacher
    8  
Court of Appeals
    31  
Credit Agreement
    45  
Crude Pipelines and Tankage Assets
    7  
CWA
    20  
DESC
    13  
EBITDA
    40  
EPA
    13  
Exchange Act
    94  
FASB
    7  
FERC
    17  
FIN
    7  
Fixed Rate Swap
    54  
GAAP
    8  
HEP
    7  
HEP CPTA
    17  
HEP Credit Agreement
    45  
HEP IPA
    17  
HEP PTA
    17  
HEP Senior Notes
    46  
Holly Asphalt
    11  
HPI
    19  
LIBOR
    54  
LIFO
    30  
MDEQ
    32  
Montana Refinery
    8  
Navajo Refinery
    7  
NEP
    33  
NMED
    32  
NPDES
    20  
Ominbus Agreement
    13  
OSHA
    33  
PEMEX
    9  
Plains
    11  
Plan
    89  
PPI
    17  
Rio Grande
    7  
Rocky Mountain
    33  
SEC
    7  
SDWA
    20  
SFAS
    53  
SFPP
    11  
SLC Pipeline
    19  
South System
    19  
UNEV Pipeline
    16  
UOSH
    33  
Variable Rate Swap
    54  
VIE
    7  
VRDN
    45  
Woods Cross Refinery
    7  
WRB
    11  
Terms used in the financial statements and footnotes are as defined therein.

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Items 1 and 2. Business and Properties
COMPANY OVERVIEW
References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.
We are principally an independent petroleum refiner that produces high value light products such as gasoline, diesel fuel and jet fuel. We were incorporated in Delaware in 1947 and maintain our principal corporate offices at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915. Our telephone number is 214-871-3555 and our internet website address is www.hollycorp.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A print copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the SEC website is available on our website on the Investors page. Also available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, Nominating / Corporate Governance Committee Charter and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. Our Code of Business Conduct and Ethics applies to all of our officers, employees and directors, including our principal executive officer, principal financial officer and principal accounting officer. Our common stock is traded on the New York Stock Exchange under the trading symbol “HOC.”
In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that also trades on the New York Stock Exchange under the trading symbol “HEP”. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).
On February 29, 2008, we closed on the sale of certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within both of our refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico and crude oil and product pipelines that support our refinery in Woods Cross, Utah. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.
HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standard Board (“FASB”) Interpretation (“FIN”) No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.
As of December 31, 2008, we:
    owned and operated two refineries consisting of a petroleum refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively known as the “Navajo Refinery”), and a refinery in Woods Cross, Utah (“Woods Cross Refinery”);

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    owned and operated Holly Asphalt Company (formerly, NK Asphalt Partners) which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and
 
    owned a 46% interest in HEP (which includes our 2% general partnership interest), which has logistics assets including approximately 2,600 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; two refinery truck rack facilities; a refined products tank farm facility; on-site crude oil tankage at both our Navajo and Woods Cross Refineries and a 70% interest in Rio Grande.
Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns the Navajo Refinery. The Navajo Refinery has a crude capacity of 85,000 BPSD, can process up to approximately 90% sour crude oil and serves markets in the southwestern United States and northern Mexico. Our Woods Cross Refinery, located just north of Salt Lake City, Utah has a crude capacity of 31,000 BPSD and is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that processes regional sweet and Canadian sour crude oils.
On March 31, 2006 we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). Accordingly, the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale are shown in discontinued operations.
Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation).
REFINERY OPERATIONS
Our refinery operations include the Navajo Refinery and the Woods Cross Refinery. The following table sets forth information, including performance measures about our refinery operations that are not calculations based upon U.S. generally accepted accounting principles (“GAAP”). The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. Information regarding our individual refineries is provided later in this section of “Refinery Operations.”
                         
    Years Ended December 31,  
    2008     2007     2006  
Consolidated(8)
                       
Crude charge (BPD) (1)
    100,680       103,490       96,570  
Refinery production (BPD) (2)
    110,850       113,270       105,730  
Sales of produced refined products (BPD)
    111,950       115,050       105,090  
Sales of refined products (BPD) (3)
    120,750       126,800       119,870  
 
                       
Refinery utilization (4)
    89.7 %     94.1 %     92.4 %
 
                       
Average per produced barrel (5)
                       
Net sales
  $ 108.83     $ 89.77     $ 80.21  
Cost of products(6)
    97.87       73.03       64.43  
 
                 
Refinery gross margin
    10.96       16.74       15.78  
Refinery operating expenses (7)
    5.14       4.43       4.83  
 
                 
Net operating margin
  $ 5.82     $ 12.31     $ 10.95  
 
                 
 
                       
Feedstocks:
                       
Sour crude oil
    63 %     62 %     61 %
Sweet crude oil
    23 %     23 %     25 %
Black wax crude oil
    4 %     3 %     3 %
Other feedstocks and blends
    10 %     12 %     11 %
 
                 
Total
    100 %     100 %     100 %
 
                 

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(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 101,000 BPSD to 109,000 BPSD during 2006, from 109,000 BPSD to 111,000 BPSD in mid-year 2007 and by an additional 5,000 BPSD in the fourth quarter of 2008, increasing our consolidated crude capacity to 116,000 BPSD.
 
(5)   Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
(6)   Transportation costs billed from HEP are included in cost of products.
 
(7)   Represents operating expenses of our refineries, exclusive of depreciation and amortization.
 
(8)   The Montana Refinery was sold on March 31, 2006. Amounts reported are for the Navajo and Woods Cross Refineries.
Set forth below is information regarding our principal products.
                         
    Years Ended December 31,  
    2008     2007     2006  
Consolidated
                       
Sales of produced refined products:
                       
Gasolines
    58 %     60 %     61 %
Diesel fuels
    32 %     29 %     28 %
Jet fuels
    1 %     2 %     3 %
Fuel oil
    3 %     4 %     3 %
Asphalt
    3 %     2 %     2 %
LPG and other
    3 %     3 %     3 %
 
                 
Total
    100 %     100 %     100 %
 
                 
We have several significant customers, none of which accounts for more than 10% of our business. Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for military and domestic airline use. Asphalt is sold to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing or blended into fuel oil.
Navajo Refinery
Facilities
The Navajo Refinery has a current crude oil capacity of 85,000 BPSD and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. The Navajo Refinery converts approximately 91% of its raw materials throughput into high value light products. For 2008, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 57%, 33% and 1%, respectively, of the Navajo Refinery’s sales volumes.
The following table sets forth information about the Navajo Refinery operations, including non-GAAP performance measures. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

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    Years Ended December 31,  
    2008     2007     2006  
Navajo Refinery
                       
Crude charge (BPD) (1)
    79,020       79,460       72,930  
Refinery production (BPD) (2)
    88,680       87,930       80,540  
Sales of produced refined products (BPD)
    89,580       88,920       79,940  
Sales of refined products (BPD) (3)
    97,320       100,460       93,660  
 
                       
Refinery utilization (4)
    93.0 %     94.6 %     92.9 %
 
                       
Average per produced barrel (5)
                       
Net sales
  $ 108.52     $ 89.68     $ 79.62  
Cost of products(6)
    98.97       74.10       64.25  
 
                 
Refinery gross margin
    9.55       15.58       15.37  
Refinery operating expenses (7)
    4.58       4.30       4.74  
 
                 
Net operating margin
  $ 4.97     $ 11.28     $ 10.63  
 
                 
 
                       
Feedstocks:
                       
Sour crude oil
    79 %     82 %     80 %
Sweet crude oil
    10 %     9 %     8 %
Other feedstocks and blends
    11 %     9 %     12 %
 
                 
Total
    100 %     100 %     100 %
 
                 
 
(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refinery.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased from 75,000 BPSD to 83,000 BPSD during 2006 and by an additional 2,000 BPSD in mid-year 2007, increasing crude capacity to 85,000 BPSD.
 
(5)   Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
(6)   Transportation costs billed from HEP are included in cost of products.
 
(7)   Represents operating expenses of the refinery, exclusive of depreciation and amortization.
The Navajo Refinery’s Artesia, New Mexico facility is located on a 561 acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 2.0 million barrels of feedstock and product tankage at the site of which 0.2 million is owned by HEP, maintenance shops, warehouses and office buildings. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. The Artesia facility is operated in conjunction with an integrated refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970. The facility also has an additional 1.1 million barrels of feedstock and product tankage of which 0.2 million is owned by HEP. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of two intermediate pipelines owned by HEP. These products are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Navajo facilities is 85,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.
We also own 67 crude oil trucks and 67 trailers that support operations at our Navajo Refinery facilities.
We distribute refined products from the Navajo Refinery to markets in Arizona, New Mexico and west Texas primarily through two of HEP’s owned pipelines that extend from Artesia, New Mexico to El Paso, Texas. In addition, we use pipelines owned and leased by HEP to transport petroleum products to markets in central and

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northwest New Mexico. We have refined product storage through our pipelines and terminals agreement with HEP at terminals in El Paso, Texas; Tucson, Arizona; and Artesia, Moriarty and Bloomfield, New Mexico.
We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Texas and northern Mexico under Holly Asphalt Company (“Holly Asphalt”). We have three manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico and Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo Refinery and third-party suppliers. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our Navajo and Woods Cross Refineries and third-party suppliers. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.
Markets and Competition
The Navajo Refinery primarily serves the growing southwestern United States market, including El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and the northern Mexico market. Our products are shipped through HEP’s pipelines from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Plains All American Pipeline, L.P. (“Plains”) and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan’s SFPP, L.P. (“SFPP”). In addition, the Navajo Refinery transports petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via HEP’s pipelines running from Artesia to San Juan County, New Mexico.
El Paso Market
The El Paso market for refined products is currently supplied by a number of area refiners, gulf coast refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between ConocoPhillips and EnCana Corp.), Valero, Alon, and Western Refining. Pipelines serving this market include Longhorn, Magellan, NuStar and HEP pipelines. Refined products from the Gulf Coast are transported via the Longhorn and Magellan pipelines. We currently supply approximately 11,000 BPD to the El Paso market, which accounts for approximately 18% of the refined products consumed in that market.
Arizona Market
The Arizona market for refined products is currently supplied by a number of refiners via pipelines and trucks. Refiners include companies located in west Texas, eastern New Mexico, northern New Mexico, the Gulf Coast and West Coast. We currently supply approximately 52,000 BPD of refined products via the SFPP Pipeline into the Arizona market, comprised primarily of Phoenix and Tucson, which accounts for approximately 17% of the refined products consumed in that market.
New Mexico Markets
The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western, Alon and WRB. We currently supply approximately 22,000 BPD of refined products to the New Mexico market, which accounts for approximately 20% of the refined products consumed in that market.
The common carrier pipeline we use to serve the Albuquerque market out of El Paso currently operates at near capacity. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the Leased Pipeline as well as terminalling facilities in Bloomfield, New Mexico, which is located in the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of Albuquerque. These facilities permit us to provide a total of up to 45,000 BPD of light products to the growing Albuquerque and Santa Fe, New Mexico areas. If needed, additional pump stations could further increase the pipeline’s capabilities.
The Longhorn Pipeline is a 72,000 BPD common carrier pipeline that has the ability to deliver refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. In 2008, Longhorn Partners Pipeline, L.P., owner of the pipeline, filed for

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bankruptcy and has put the pipeline up for sale. Flying J, the pipeline’s major shipper also filed for bankruptcy in 2008. The status of current shipping levels is presently unknown.
An additional factor that could affect some of our markets is the presence of pipeline capacity from El Paso and the West Coast into our Arizona markets. Additional increases in shipments of refined products from El Paso and the West Coast into our Arizona markets could result in additional downward pressure on refined product prices in these markets.
Crude Oil and Feedstock Supplies
The Navajo Refinery is situated near the Permian Basin in an area that historically has had abundant supplies of crude oil available both for regional users, such as us, and for export to other areas. We purchase crude oil from producers in nearby southeastern New Mexico and west Texas and from major oil companies. Crude oil is gathered both through HEP’s pipelines and our tank trucks and through third-party crude oil pipeline systems. Crude oil acquired in locations distant from the refinery is exchanged for crude oil that is transportable to the refinery.
We also purchase isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery. In 2008, approximately 4,900 BPD of isobutane and 5,000 BPD of natural gasoline used in the Navajo Refinery’s operations were purchased from a newly operational fractionation facility in Hobbs, New Mexico, which is owned by Enterprise Products, L.P. as well as volumes purchased from the mid-continent area and delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP’s two parallel 65-mile pipelines running from Lovington to Artesia. From time to time, we also purchase gas oil, naphtha and light cycle oil from other oil companies for use as feedstock.
Principal Products and Customers
Set forth below is information regarding the principal products produced at the Navajo Refinery:
                         
    Years Ended December 31,
    2008   2007   2006
Navajo Refinery
                       
Sales of produced refined products:
                       
Gasolines
    57 %     59 %     60 %
Diesel fuels
    33 %     30 %     28 %
Jet fuels
    1 %     3 %     4 %
Fuel oil
    3 %     3 %     2 %
Asphalt
    3 %     2 %     3 %
LPG and other
    3 %     3 %     3 %
 
                       
Total
    100 %     100 %     100 %
 
                       
Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.
Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, and retailers. Our gasoline produced at the Navajo Refinery is marketed in the southwestern United States, including the metropolitan areas of El Paso, Phoenix, Albuquerque, Bloomfield, and Tucson, and in portions of northern Mexico. The composition of gasoline differs, because of local regulatory requirements, depending on the area in which gasoline is to be sold. Diesel fuel is sold to other refiners, truck stop chains, wholesalers, and railroads. Jet fuel is sold for military use. All asphalt produced at the Navajo Refinery and third-party purchased asphalt is marketed through Holly Asphalt to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing.
Military jet fuel is sold to the Defense Energy Support Center, a part of the United States Department of Defense (the “DESC”), under a series of one-year contracts that can vary significantly from year to year. We sold approximately 775 BPD of jet fuel to the DESC in 2008. We have had a military jet fuel supply contract with the United States Government for each of the last 39 years. Our size in terms of employees and refining capacity allows us to bid for military jet fuel sales contracts under a small business set-aside program. In September 2008, the DESC awarded us contracts for sales of military jet fuel for the period from October 1, 2008 through September 30,

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2009. Our total contract award, which is subject to adjustment based on actual needs of the DESC for military jet fuel, is 12.7 million gallons as compared to the total award for the 2007-2008 contract year of 22.0 million gallons.
Capital Improvement Projects
We have invested significant amounts in capital expenditures in recent years to expand and enhance the Navajo Refinery and expand our supply and distribution network.
Our Board of Directors approved a capital budget for 2009 of $11.4 million for refining improvement projects at the Navajo Refinery, not including the capital projects approved in prior years or our expansion and feedstock flexibility projects described below.
At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant, and the expansion of our Lovington crude and vacuum units. Phase I is expected to be mechanically complete in the first quarter of 2009 and was originally estimated to cost $163.0 million. The total cost of phase I is now expected to be approximately $185.0 million. The added costs are associated with permit timing delays, scope changes due to permit required pollution control equipment that was not anticipated, material cost escalation and increased labor rates.
Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 and was originally estimated to cost $84.0 million. The total cost of phase II is now expected to be approximately $96.0 million. The added costs are associated with better scope definition on the Artesia crude and vacuum unit revamp portion of the overall project and material cost escalation.
We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $15.0 million and are expected to be completed at the same time as the phase II project.
The Navajo Refinery is also installing a new 100 ton per day sulfur recovery unit that is scheduled for mechanical completion in the first quarter of 2009. The project was originally estimated to cost $26.0 million and is now projected to cost $31.0 million. The added costs are associated permit delays, material cost escalation and increased labor rates.
Once the Navajo projects discussed above are complete, the Navajo Refinery will be able to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt with all their performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks and enable the refinery to meet new LSG specifications required by the Environmental Protection Agency (“EPA”).
In July 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion’s pipeline from Cushing, Oklahoma to its Slaughter Station located in west Texas. Our Board of Directors has approved capital expenditures of up to $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico and a 65-mile pipeline from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline project that connects HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. Under the provisions of our omnibus agreement with HEP (the “Omnibus Agreement”), HEP will have an option to purchase these transportation assets upon our completion of these projects. We expect to complete these projects in the fourth quarter of 2009.

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Woods Cross Refinery
Facilities
The Woods Cross Refinery has a crude oil capacity of 31,000 BPSD and is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly owned subsidiaries. The Woods Cross Refinery is located in Woods Cross, Utah and processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2008, gasoline and diesel fuel (excluding volumes purchased for resale) represented 63% and 29%, respectively, of the Woods Cross Refinery’s sales volumes.
The following table sets forth information about the Woods Cross Refinery operations, including non-GAAP performance measures about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
                         
    Years Ended December 31,  
    2008     2007     2006  
Woods Cross Refinery
                       
Crude charge (BPD) (1)
    21,660       24,030       23,640  
Refinery production (BPD) (2)
    22,170       25,340       25,190  
Sales of produced refined products (BPD)
    22,370       26,130       25,150  
Sales of refined products (BPD) (3)
    23,430       26,340       26,210  
 
                       
Refinery utilization (4)
    79.5 %     92.4 %     90.9 %
 
                       
Average per produced barrel (5)
                       
Net sales
  $ 110.07     $ 90.09     $ 82.09  
Cost of products (6)
    93.47       69.40       64.99  
 
                 
Refinery gross margin
    16.60       20.69       17.10  
Refinery operating expenses (7)
    7.42       4.86       5.13  
 
                 
Net operating margin
  $ 9.18     $ 15.83     $ 11.97  
 
                 
 
                       
Feedstocks:
                       
Sour crude oil
    1 %     2 %     2 %
Sweet crude oil
    72 %     75 %     79 %
Black wax crude oil
    21 %     15 %     10 %
Other feedstocks and blends
    6 %     8 %     9 %
 
                 
Total
    100 %     100 %     100 %
 
                 
 
(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refinery.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased by 5,000 BPSD in the fourth quarter of 2008, increasing crude capacity to 31,000 BPSD.
 
(5)   Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
(6)   Transportation costs billed from HEP are included in cost of products.
 
(7)   Represents operating expenses of the refinery, exclusive of depreciation and amortization.
The Woods Cross Refinery facility is located on a 200 acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 1.5 million barrels of feedstock and product tankage of which 0.2 million is owned by HEP, maintenance shops, warehouses and office buildings. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since

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before 1950. The crude oil capacity of the Woods Cross Refinery is 31,000 BPSD and the facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane, and gas oil.
We own and operate 2 miles of hydrogen pipeline that allows us to connect to a hydrogen plant located at Chevron’s Salt Lake City Refinery. Additionally, HEP owns and operates 12 miles of crude oil and refined products pipelines that allow us to connect our Woods Cross Refinery to common carrier pipeline systems.
Markets and Competition
The Woods Cross Refinery is one of five refineries located in Utah. We estimate that the four refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately 150,000 BPD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and ConocoPhillips. The Woods Cross Refinery’s primary markets include Utah, Idaho, Nevada, Wyoming and eastern Washington. Approximately 60% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under a long-term supply agreement.
Utah Market
The Utah market for refined products is currently supplied primarily by a number of local refiners and the Pioneer Pipeline. Local area refiners include Woods Cross, Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and ConocoPhillips. We currently supply approximately 16,000 BPD of refined products into the Utah market, which represents approximately 15% of the refined products consumed in that market, to branded and unbranded customers.
Idaho, Wyoming, Eastern Washington and Nevada Markets
We currently supply approximately 7,000 BPD of refined products into the Idaho, Wyoming, eastern Washington and Nevada markets, which represents approximately 2% of the refined products consumed in those markets. Woods Cross ships refined products over Chevron’s common carrier pipeline system to numerous terminals, including HEP’s terminals at Boise and Burley, Idaho and Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Northwest Terminalling Pipeline Company. We sell to branded and unbranded customers in these markets. We also truck refined products to Las Vegas, Nevada.
The Idaho market for refined products is primarily supplied via Chevron’s common carrier pipeline system from refiners located in the Salt Lake City area and products supplied from the Pioneer Pipeline system. Refiners that could potentially supply the Chevron and Pioneer Pipeline systems include Woods Cross, Chevron, Tesoro, Big West, Silver Eagle, Sinclair, ConocoPhillips and ExxonMobil.
We market refined products in the Wyoming market on a limited basis. Refiners that supply Wyoming include Sinclair, ConocoPhillips, ExxonMobil and Frontier.
The eastern Washington market is supplied by two common carrier pipelines, Chevron and Yellowstone. Product is also shipped into the area via rail from various points in the United States and Canada. Refined products shipped on Chevron’s pipeline system are supplied by refiners and other pipelines located in the Salt Lake City area and from refiners located in the Pacific Northwest. Pacific Northwest refiners include BP, Tesoro, Shell, ConocoPhillips and US Oil. Products supplied from the sources located in the Pacific Northwest area are generally shipped over the Columbia River via barge at Pasco, Washington.
The majority of the Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan’s CalNev common carrier pipeline system.

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Principal Products and Customers
Set forth below is information regarding the principal products produced at the Woods Cross Refinery:
                         
    Years Ended December 31,
    2008   2007   2006
Woods Cross Refinery
                       
Sales of produced refined products:
                       
Gasolines
    63 %     63 %     63 %
Diesel fuels
    29 %     27 %     28 %
Jet fuels
    %     2 %     2 %
Fuel oil
    5 %     5 %     5 %
Asphalt
    1 %     1 %     %
LPG and other
    2 %     2 %     2 %
 
                       
Total
    100 %     100 %     100 %
 
                       
Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.
Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, due to local regulatory requirements, depending on the area in which gasoline is to be sold. Diesel fuel is sold to other refiners, truck stop chains and wholesalers. Limited quantities of jet fuel is sold for domestic airline use. All asphalt produced is blended to fuel oil and sold locally, railed to the Gulf Coast, railed directly to our customers or marketed through Holly Asphalt Company to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers.
Crude Oil and Feedstock Supplies
The Woods Cross Refinery currently obtains its supply of crude oil primarily from suppliers in Canada, Wyoming, Utah and Colorado via common carrier pipelines that originate in Canada, Wyoming and Colorado. Supplies of black wax crude oil are shipped via truck.
Capital Improvement Projects
Our approved capital budget for 2009 capital projects at the Woods Cross Refinery is $5.3 million not including the major projects described below or other capital projects approved in prior years.
At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipment and black wax unloading systems. The total cost of this project was approximately $122.0 million versus our original $105.0 million estimate. Increased costs resulted from offsite scope additions, material cost escalation and increased labor rates. The projects were completed in the fourth quarter of 2008. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.
To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. HEP’s joint venture pipeline with Plains will permit the transportation of additional crude oil into the Salt Lake City area. HEP’s joint venture project with Plains is further described under the HEP section of this discussion of business and properties.
In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the “UNEV Pipeline”). Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million, with our share of the cost totaling $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered into an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture

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pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum. Additionally in 2008, we purchased a terminal and rail facility located near Cedar City, Utah that will serve as a key component of our UNEV joint venture pipeline.
The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.
Holly Energy Partners, L.P.
In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that also trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande.
HEP owns and operates a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah and distribution terminals and refinery tankage in Texas, New Mexico, Arizona, Utah, Idaho and Washington. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals; therefore, it is not directly exposed to changes in commodity prices.
Transportation Agreements
HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (the “HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (the “HEP IPA”). Under these agreements, we pay HEP fees to transport and store volumes of refined product on HEP’s pipelines and terminal facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change equal to the change in the producer price index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in PPI, but not below the initial tariff rate. Following the July 1, 2008 PPI rate adjustment, minimum payments under the HEP PTA and the HEP IPA are $41.2 million and $13.3 million, respectively, for the twelve months ending June 30, 2009.
In connection with our sale of the Crude Pipelines and Tankage Assets to HEP, we entered into a 15-year crude pipelines and tankage agreement with HEP (the “HEP CPTA”). Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the PPI, but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a FERC adjustment factor. Additionally, we amended the Omnibus Agreement with HEP to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.
HEP also has a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on HEP’s pipelines and throughput through their terminals volumes of refined products that results in a minimum level of annual revenue. Under the Alon PTA, the agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

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As of December 31, 2008, HEP’s contractual minimum revenues under long-term service agreements are as follows:
               
    Minimum Annualized        
    Commitment   Year of    
       Agreement   (In millions)   Maturity   Contract Type
HEP PTA(1)
  $ 41.2   2019   Minimum revenue commitment
HEP IPA(1)
    13.3   2020   Minimum revenue commitment
HEP CPTA(1)
    26.8   2023   Minimum revenue commitment
Alon PTA(2)
    22.0   2020   Minimum volume commitment
Alon capacity lease(2)
    6.8   Various   Capacity lease
 
           
 
             
Total
  $ 110.1        
 
           
 
(1)   HEP’s revenue under the HEP PTA, HEP IPA and HEP CPTA represents intercompany revenue and is eliminated in our consolidated financial statements.
 
(2)   Minimum annual revenues attributable to long-term service contracts with unaffiliated parties is $28.8 million.
As of December 31, 2008, HEP’s assets include:
Pipelines
    approximately 820 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico;
 
    approximately 510 miles of refined product pipelines that transport refined products from Alon’s Big Spring refinery in Texas to its customers in Texas and Oklahoma;
 
    two parallel 65-mile pipelines that transport intermediate feedstocks and crude oil from our Lovington, New Mexico refinery facilities to our Artesia, New Mexico refining facilities;
 
    approximately 860 miles of crude oil trunk, gathering and connection pipelines located in west Texas and New Mexico that deliver crude oil to our Navajo Refinery;
 
    approximately 10 miles of crude oil and refined product pipelines that support our Woods Cross Refinery near Salt Lake City, Utah; and
 
    a 70% interest in Rio Grande, a joint venture that owns a 249-mile refined product pipeline that transports liquid petroleum gases, or LPG’s, from west Texas to the Texas/Mexico border near El Paso for further transport into northern Mexico.
Refined Product Terminals and Refinery Tankage
    four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1.0 million barrels, that are integrated with HEP’s refined product pipeline system that serves our Navajo Refinery;
 
    three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000 barrels, that serve third-party common carrier pipelines;
 
    one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;
 
    two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with HEP’s refined product pipelines that serve Alon’s Big Spring, Texas refinery;
 
    two refined product truck loading racks, one located within our Navajo Refinery that is permitted to load over 40,000 BPD of light refined products, and one located within our Woods Cross Refinery near Salt Lake City, Utah, that is permitted to load over 25,000 BPD of light refined products.
 
    a Roswell, New Mexico jet fuel terminal leased through September 2011; and
 
    on-site crude oil tankage at our Navajo and Woods Cross Refineries having an aggregate storage capacity of approximately 600,000 barrels.

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Capital Improvement Projects
HEP’s capital budget for 2009 is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of HEP’s pipeline system between Artesia, New Mexico and El Paso, Texas (the “South System”) and the joint venture with Plains discussed below.
In October 2007, we amended the HEP PTA under which HEP has agreed to expand their South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at HEP’s El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. HEP expects to complete the majority of this project in early 2009.
In November 2007, HEP executed a definitive agreement with Plains to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area (the “SLC Pipeline”). Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by HEP. HEP expects to purchase their 25% interest in the joint venture in March 2009 when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including our Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah that is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of HEP’s investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to us upon the closing of their investment in the SLC Pipeline.
HEP is currently working on a capital improvement project that will provide increased flexibility and capacity to their intermediate pipelines enabling them to accommodate increased volumes following the completion of our Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $5.1 million.
Also, HEP is currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline at an estimated cost of $1.9 million for completion in early 2009.
ADDITIONAL OPERATIONS AND OTHER INFORMATION
Corporate Offices
We lease our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires June 30, 2011, requires lease payments of approximately $115,000 per month plus certain operating expenses and provides for one five-year renewal period. Functions performed in the Dallas office include overall corporate management, refinery and HEP management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
Exploration and Production
A subsidiary, Holly Petroleum, Inc. (“HPI”) previously conducted a small-scale oil and gas exploration and production program. We sold substantially all of the oil and gas properties in 2008 for $6.0 million, resulting in a gain of $6.0 million.
Employees and Labor Relations
As of December 31, 2008, we had 978 employees, of which 339 are currently covered by collective bargaining agreements. We consider our employee relations to be good. We successfully renegotiated the collective bargaining agreement for our Utah refinery and extended the term to 2012 in February, 2009 (subject only to ongoing efforts to document the interim letter agreement with formal contract terms) and the collective bargaining agreement for our New Mexico refinery expires in 2010.

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Regulation
Refinery and pipeline operations are subject to federal, state and local laws regulating the discharge of matter into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
Our operations and many of the products we manufacture are subject to certain specific requirements of the Federal Clean Air Act (“CAA”) and related state and local regulations. The CAA contains provisions that require capital expenditures for the installation of certain air pollution control devices at our refineries. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules, may necessitate additional expenditures in future years.
In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal CAA liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement for a Consent Decree. The agreement was signed by the parties and approved and entered by the federal district court in Utah in 2008. It includes obligations for us to make specified additional capital investments currently estimated to total approximately $17.0 million over several years and to make changes in operating procedures at the refinery. The agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit to the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the anticipated settlement.
Under the CAA, the EPA has the authority to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. For example, in June 2004, the EPA issued new regulations limiting emissions from diesel fuel powered engines used in non-road activities such as mining, construction, agriculture, railroad and marine and simultaneously limiting the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. Both of our refineries met the ultimate 15 PPM standard for both our non-road and highway diesel fuel by June 1, 2006. Although the highway and non-road diesel sulfur regulations provided for a timed phase-in of the low sulfur requirements with extended compliance dates for small refiners such as us, we met these standards by the earliest deadline for large refiners. This entailed substantial capital expenditures. Also, by January 1 2011, we will be required to meet another EPA regulation limiting the average concentration of sulfur in gasoline to 30 PPM. Our current capital projects include plant modifications and enhancements that will enable us to meet this new LSG requirement.
We are currently making plans to comply with new EPA regulations on gasoline that will impose further reductions in the benzene content of our produced gasoline and would mandate the blending of prescribed, substantial percentages of renewable fuels (e.g. ethanol) into our produced gasoline. Both of these initiatives contain mitigating provisions for small refiners such as us. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may cause us to make substantial capital expenditures to enable our refineries to produce products that meet applicable requirements.
Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in strict conformance with permits, such as pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.

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We generate wastes that may be subject to the Resource Conservation and Recovery Act and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In the course of our historical operations, as well as in our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from past releases of refined product and crude oil into the environment. As of December 31, 2008 we had an accrual of $7.3 million related to such environmental liabilities of which $4.2 million was classified as long-term.
We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries, including those discussed above. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at pipeline transportation facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.
Insurance
Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
We have formed a risk management oversight committee that is made up of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.

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Item 1A. Risk Factors
Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition or results of operations could be materially and adversely affected.
The prices of crude oil and refined products materially affect our profitability, and are dependent upon many factors that are beyond our control, including general market demand and economic conditions, seasonal and weather-related factors and governmental regulations and policies.
Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve, and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.
We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year. In general, prices for refined products are influenced by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on operating results therefore depends in part on how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings and cash flows. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial results.
In addition, we currently process volumes of lower cost crude oils, such as regional sour, heavy Canadian and Black Wax. As part of our current capital initiatives, we plan on providing additional flexibility to both our Navajo and Woods Cross Refineries that will allow us to process a greater degree of these lower cost crude oils. In recent years, the spread or differential between these lower cost heavy/sour crude oils and higher priced light/sweet crude oils has widened. A substantial or prolonged decrease in these crude oil differentials could negatively impact our earnings and cash flows.

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We may not be able to successfully execute our business strategies to grow our business.
One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets such as our UNEV Pipeline joint venture, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada that is currently under construction and in which our subsidiary owns a 75% interest. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including: denial or delay in issuing requisite regulatory approvals and/or permits; compliance with or liability under environmental regulations; unplanned increases in the cost of construction materials or labor; disruptions in transportation of modular components and/or construction materials; severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers; shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; and/or nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project. These projects may not be completed on schedule or at all or at the budgeted cost. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new refinery processing unit, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new capital investments may not achieve our expected investment return, which could adversely affect our results of operations and financial condition.
Our forecasted internal rates of return are also based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply and customer demand.
In addition, a component of our growth strategy is to selectively acquire complementary assets for our refining operations in order to increase earnings and cash flow. Our ability to do so will be dependent upon a number of factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and other factors beyond our control. Risks associated with acquisitions include those relating to:
  diversion of management time and attention from our existing business;
 
  challenges in managing the increased scope, geographic diversity and complexity of operations;
 
  difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
 
  liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
 
  greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
 
  difficulties in achieving anticipated operational improvements;
 
  incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
 
  issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

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To successfully operate our petroleum refining facilities, we are required to expend significant amounts for capital outlays and operating expenditures.
The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related facilities. We are dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.
Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; the yield and product quality of new equipment may differ from design and/or specifications and redesign or modification of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future results of operations and financial condition.
In addition, we expect to execute turnarounds at our refineries every three to five years, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime. The Woods Cross refinery turnaround occurred in August/September, 2008, and the Navajo refinery turnaround occurred in January/February, 2009.
We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters.
Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements.
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed.

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We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However, new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. There is growing consensus that some form of regulation will be forthcoming at the federal level in the United States with respect to greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides). Also, new federal or state legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our products.
The costs of environmental and safety regulations are already significant and compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.
From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.
For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.”
Insufficient ethanol supplies or disruption in ethanol supply may disrupt our ability to market ethanol blended fuels.
If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits.
Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry.

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We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be material adverse effects on our business, financial condition and results of operations.
In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us.
Portions of our operations in the areas we operate may be impacted by competitors’ plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability.
In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing sales agreements with our customers depends on a number of factors outside our control, including competition from other refiners and the demand for refined products in the markets that we serve. Loss of, or reduction in amounts purchased by our major customers could have an adverse effect on us to the extent that, because of market limitations or transportation constraints, we are not able to correspondingly increase sales to other purchasers.
A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.
In order to maintain or increase production levels at our refineries, we must continually contract for new crude oil supplies from third parties. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil available to our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries’ production capacities.
The potential operation of new refined product transportation pipelines or disruption or proration of existing pipelines could impact the supply of refined products to our existing markets, including El Paso, Albuquerque and Phoenix.
If one of the major refined products pipelines becomes inoperative, we would be required to keep refined products in inventory or supply refined products to our customers through an alternative pipeline or by additional tanker trucks from the refinery, which could increase our costs and result in a decline in profitability. The Longhorn Pipeline is an approximately 72,000 BPD common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the

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Arizona market. Longhorn Pipeline is a wholly-owned subsidiary of Flying J Inc. On December 22, 2008, both Longhorn Pipeline and Flying J Inc. filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. The status of current shipping levels is currently unknown. The future ownership and operation of the Longhorn Pipeline is uncertain pending resolution of the bankruptcy proceedings. Increased supplies of refined product delivered by the Longhorn Pipeline and Kinder Morgan’s El Paso to Phoenix pipeline could result in additional downward pressure on wholesale refined product prices and refined product margins in El Paso, Arizona and related markets.
An additional factor that could affect some of our markets is the presence of pipeline capacity from the West Coast into our Arizona markets. Additional increases in shipments of refined products from the West Coast into the Arizona markets could result in additional downward pressure on refined product prices in these markets.
In addition to the projects described above, other projects have been explored from time to time by refiners and other entities which if completed, could result in further increases in the supply of products to our markets. For example, competitors may rely on alternate methods of transportation, such as trucking, to increase the volume of refined products entering our markets. Such alternatives may decrease the price of refined products or decrease our ability to market our refined products in those markets.
In the case of the Albuquerque market, the common carrier pipeline we use to serve this market out of El Paso currently operates at near capacity. However, through our relationship with HEP, our Navajo Refinery has pipeline access to the Albuquerque vicinity and to Bloomfield, New Mexico, that will permit us to deliver a total of up to 45,000 BPD of light products to these locations, thereby eliminating the risk of future pipeline constraints on shipments to Albuquerque. If needed, additional pump stations could further increase HEP’s pipeline capabilities. Any future pipeline constraints or disruptions affecting our ability to transport refined products to Arizona or Albuquerque could, if sustained, adversely affect our results of operations and financial condition.
For additional information on competition in our markets due to new product transportation pipelines or proration of existing pipelines, see “Markets and Competition” under the “Navajo Refinery” discussion under Items 1 and 2, “Business and Properties.”
We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries and we own a significant equity interest in HEP.
We currently own a 46% interest in HEP, including the 2% general partner interest. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves our refineries in New Mexico and Utah under three 15-year pipelines and terminals and tankage agreements expiring in 2019 through 2023. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to:
    its reliance on its significant customers, including us,
 
    competition from other pipelines,
 
    environmental regulations affecting pipeline operations,
 
    operational hazards and risks,
 
    pipeline tariff regulations affecting the rates HEP can charge,
 
    limitations on additional borrowings and other restrictions due to HEP’s debt covenants, and
 
    other financial, operational and legal risks.
The occurrence of any of these risks could directly or indirectly affect HEP’s as well as our financial condition, results of operations and cash flows as HEP is a consolidated subsidiary. Additionally, these risks could affect HEP’s ability to continue operations which could affect their ability to serve our supply and distribution network needs.

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For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.”
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations and may affect our ability to meet marketing commitments. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice, or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.
If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.
Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance, non-compete agreements, or employment agreements with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.
Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations.

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As of December 31, 2008, approximately 35% of our employees were represented by labor unions under collective bargaining agreements expiring in 2009 through 2010. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.
We are exposed to the credit risks of our key customers.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks.
Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
The long-term impacts of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, are not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.
Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage.
Our petroleum business’ financial results are seasonal and generally lower in the first and fourth quarters of the year, which may cause volatility in the price of our common stock.
Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel fuel, which in the Southwest region of the United States is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes. However, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and reduce operating margins.
Ongoing maintenance of effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.
We regularly document and test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our internal controls and, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could cause us to incur substantial expenditures of management time and financial resources to identify and correct any such failure.

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Additionally, the failure to comply with Section 404 or the report by us of a “material weakness” may cause investors to lose confidence in our financial statements and our stock price may be adversely affected. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may decline.
Product liability claims and litigation could adversely affect our business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations. Failure of our products to meet required specifications could result in product liability claims from our shippers and customers arising from contaminated or off-specification commingled pipelines and storage tanks and/or defective quality fuels.
If the market value of our inventory declines to an amount less than our LIFO basis, we would record a write-down of inventory and a non-cash charge to cost of sales, which would adversely affect our earnings.
The nature of our business requires us to maintain substantial quantities of crude oil, refined petroleum product and blendstock inventories. Because crude oil and refined petroleum products are commodities, we have no control over the changing market value of these inventories. Because certain of our refining inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology, we would record a write-down of inventory and a non-cash charge to cost of sales if the market value of our inventory were to decline to an amount less than our LIFO basis. A material write-down could affect our operating income and profitability.
From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are not able to obtain the necessary funds from financing activities.
We have significant short-term cash needs to satisfy working capital requirements such as crude oil purchases which fluctuate with the pricing and sourcing of crude oil.
We generally purchase crude oil for our refineries with cash generated from our operations. If the price of crude oil increases significantly, we may not have sufficient cash flow or borrowing capacity, and may not be able to sufficiently increase borrowing capacity, under our existing credit facilities to purchase enough crude oil to operate our refineries at full capacity. Our failure to operate our refineries at full capacity could have a material adverse effect on our business, financial condition and results of operations. We also have significant long-term needs for cash, including those to support our expansion and upgrade plans, as well as for regulatory compliance. If credit markets tighten, it may become more difficult to obtain cash from third party sources. If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with regulatory deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect and we could be subject to regulatory action.
Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and limit our ability to purchase enough crude oil to operate our refineries at full capacity.
An unfavorable credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flow.

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Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.
The operating and financial restrictions and covenants in our credit facilities and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our revolving credit facility imposes usual and customary requirements for this type of credit facility, including: (i) maintenance of certain levels of interest coverage and leverage ratios; (ii) limitations on liens, investments, indebtedness and dividends; (iii) a prohibition on changes in control and (iv) restrictions on engaging in mergers, consolidations and sales of assets, entering into certain lease obligations, and making certain investments or capital expenditures. If we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to obtain, sufficient funds to make these immediate payments. Should we desire to undertake a transaction that is prohibited by the covenants in our credit facilities, we will need to obtain consent under our credit facilities. Such refinancing may not be possible or may not be available on commercially acceptable terms, or at all. In addition, our obligations under our credit facilities are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facilities when due, the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.
We may need to use current cash flow to fund our pension and postretirement health care obligations, which could have a significant adverse effect on our financial position.
We have benefit obligations in connection with our noncontributory defined benefit pension plans that provided retirement benefits for substantially all of our employees. However, effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an employee not covered by a collective bargaining agreement was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen. We expect to contribute between $10.0 million to $20.0 million to the retirement plan in 2009. Future adverse changes in the financial markets could result in significant charges to stockholders’ equity and additional significant increases in future pension expense and funding requirements.
We also have benefit obligations in connection with our unfunded postretirement health care plans that provide health care benefits as part of the voluntary early retirement program offered to eligible employees. As part of the early retirement program, we allow qualified retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. As of December 31, 2008, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7 million. Increased participation in this program and/or increasing medical costs may affect our ability to pay required health care benefits causing us to have to divert funds away from other areas of the business to pay their costs.
Item 1B. Unresolved Staff Comments
We do not have any unresolved staff comments.
Item 3. Legal Proceedings
In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the FERC in proceedings brought by us and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals

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in its May 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. The income tax issue and the other remaining issues relating to SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding covering the period from 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. A partial settlement covering the period June 2006 through November 2007, which became final in February 2008, resulted in a payment from SFPP to us of approximately $1.3 million in April 2008. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through November 2010. The Commission approved the settlement on January 29, 2009. The settlement will reduce SFPP’s current rates and require SFPP to make additional payments to us of approximately $2.0 million.
Our Navajo Refining Company subsidiary was named as a defendant, along with approximately 40 other companies involved in oil refining and marketing and related businesses, in a lawsuit originally filed in May 2006 by the State of New Mexico in the U.S. District Court for the District of New Mexico and subsequently transferred to the U.S. District Court for the Southern District of New York under multidistrict procedures along with approximately 100 similar cases, in which Navajo is not named, brought by other governmental entities and private parties in other states. The lawsuit, in which Navajo is named, as amended in October 2006 through the filing of a second amended complaint, alleges that the defendants are liable for contaminating the waters of New Mexico through producing and/or supplying MTBE or gasoline or other products containing MTBE. The lawsuit asserts claims for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy, and seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. The second amended complaint also contains a claim, asserted against certain other defendants but not against Navajo, alleging violations of certain provisions of the Toxic Substances Control Act, which appears to be similar to a claim previously threatened in a mailing to Navajo and other defendants by law firms representing the plaintiffs. Most other defendants have been dismissed from this lawsuit as a result of settlements. As of the close of business on the day prior to the date of this report, Navajo has not been served in this lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
In May 2008, Montana Refining Company, our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser in March 2006, and the unrelated company that purchased the refinery from MRC, entered into a Notice Of Violation And Administrative Order On Consent (“AOC”) with the Montana Department of Environmental Quality (“MDEQ”). The AOC relates to assertions by the MDEQ that the Great Falls refinery exceeded limitations on sulfur dioxide in the refinery’s air emission permit on certain dates in 2004 and 2005 and in 2006 both before and after the sale of the refinery, erroneously certified compliance with limitations on sulfur dioxide emissions, failed to promptly report emissions limit deviations, exceeded limits on sulfur in fuel gas on specified dates in 2005, failed in 2005 to conduct timely testing for certain emissions, submitted late a report required to be submitted in early 2006, failed to achieve a specified limitation on certain emissions in the first three quarters of 2006, and failed to timely submit a report on a 2005 emissions test. The AOC requires certain actions to be taken by the refinery and payment of a $105,000 penalty. Pursuant to the terms of the AOC, a lawsuit on this matter brought by the MDEQ in Montana state court was dismissed with prejudice in late May 2008. We paid the current owner of the Great Falls refinery $126,700 which represents our appropriate share of penalty and related amounts with respect to this matter.
In October 2008, the New Mexico Environment Department (“NMED”) issued an Amended Notice of Violation and Proposed Penalties (“Amended NOV”) to Navajo Refining Company, amending an NOV issued in February 2007. The NOV is a preliminary enforcement document issued by NMED and usually is the predicate to formal administrative or judicial enforcement. The February 2007 NOV was issued following two hazardous waste compliance evaluation inspections at the Artesia, New Mexico refinery that were conducted in April and November

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2006 and alleged violations of the New Mexico Hazardous Waste Management Regulations and Navajo’s Hazardous Waste Permit. NMED proposed a civil penalty of approximately $0.1 million for the February 2007 NOV. The Amended NOV includes additional alleged violations concerning post-closure care of a hazardous waste land treatment unit and the construction of a tank on the land treatment area. The Amended NOV also proposes an additional civil penalty of $0.3 million. Navajo has submitted responses to the February 2007 NOV and the Amended NOV, challenging certain alleged violations and proposed penalty amounts and is continuing negotiations with the NMED to resolve these matters expeditiously.
Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries are named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in state district court in Davis County, Utah involving a construction dispute regarding the installation of improvements known as a crude desalter, crude unloader, and west tank farm at our Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the construction of those improvements for which the plaintiff was not paid. The claims made against our subsidiaries are for breach of contract, lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the amount of $2.3 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the Refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Triad Engineers Limited d/b/a Triad Project Corporation, answered the complaint denying any liability, and asserted counterclaims. We intend to vigorously defend against the claims asserted in the lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries are named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in the U.S. District Court for the Central District of Utah involving a construction related dispute over the installation of an oil gas hydrocracker at the Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the installation of the oil gas hydrocracker for which the plaintiff was not paid. The claims made against our subsidiaries are for lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the approximate amount of $12.0 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Benham Constructors, LLC, and have filed an answer to the complaint denying any liability. We intend to vigorously defend against the claims asserted in the lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
Prior to the sale by Holly Corporation of the Montana Refining Company assets in 2006, MRC, along with other companies was the subject of several environmental claims at the Cut Bank Hill site in Montana. These claims include: (1) a U.S. Environmental Protection Agency administrative order requiring Montana Refining and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against Montana Refining and other companies for response costs of $298,500 in connection with its cleanup efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of Environmental Quality directing Montana Refining and other companies to complete a remedial investigation and a request by the MDEQ that Montana Refining and other companies pay $147,500 to reimburse the State’s costs for remedial actions. Montana Refining Company has denied responsibility for the requested EPA and MDEQ cleanup actions and the MDEQ and Coast Guard response costs.
On February 17, 2009, our Holly Refining & Marketing Company filed a complaint with the FERC against Plains and Rocky Mountain Pipeline LLC (“Rocky Mountain”). Plains and Rocky Mountain are affiliated companies which operate an interstate crude oil pipeline system from origin points in the Rocky Mountain region to destination points in the Rocky Mountain region. The Holly refinery at Salt Lake City uses that pipeline system to supply between 15,000 to 17,000 barrels per day of its crude oil requirements. Holly’s complaint alleges that the proposed reversal of flow on the segment of the pipeline system from Ft. Laramie, Wyoming, to Wamsutter, Wyoming, will provide an undue and unjust preference for affiliates of Plains and Rocky Mountain and will be unduly and unjustly prejudicial and discriminatory against Holly in violation of the Interstate Commerce Act. The complaint seeks an order requiring Plains and Rocky Mountain to cease and desist from the proposed reversal of flow and an award of damages to Holly for any injury caused by the reversal. Plains and Rocky Mountain have not yet answered the

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complaint. At this time, it is not known whether the FERC will assert jurisdiction over the complaint or will find that the complaint warrants discovery and hearing. Without the benefit of discovery, it is not possible to determine the likelihood of obtaining relief, including the likelihood or amount of any damages.
In June 2007, the Federal Occupational Safety and Health Administration (“OSHA”) announced a national emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As a part of the NEP, OSHA encouraged the State Plan States such as Utah to initiate their own version of the NEP. Beginning on May 1, 2008, the Utah Labor Commission, Occupational Safety and Health Division (“UOSH”) began an inspection of the refinery which is operated by Holly Refining and Marketing Company — Woods Cross and is located in Woods Cross, Utah. The inspection ended on September 18 and on October 23, 2008, UOSH issued one citation alleging 33 violations of various safety standards including the Process Safety Management Standard and proposing a penalty of $91,750. We filed a notice of contest with the Adjudicative Division, Utah Labor Commission, in Salt Lake City, Utah. On February 18, 2009, the initial status conference for this matter was held and a scheduling order will issue shortly. Our answer is due on March 4th and discovery will continue until July 6, 2009. No hearing date has been set. We intend to vigorously defend this citation and believe that we have strong defenses on the merits.
We are a party to various other litigation and proceedings not mentioned in this report that we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2008.

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PART II
Item 5.   Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange under the trading symbol “HOC.” The following table sets forth the range of the daily high and low sales prices per share of common stock, dividends declared per share and the trading volume of common stock for the periods indicated:
                                 
                            Trading
Years ended December 31,   High   Low   Dividends   Volume
2008
                               
First Quarter
  $ 56.81     $ 38.84     $ 0.15       79,892,000  
Second Quarter
  $ 49.62     $ 36.13     $ 0.15       79,585,500  
Third Quarter
  $ 37.47     $ 25.88     $ 0.15       88,195,700  
Fourth Quarter
  $ 28.83     $ 10.84     $ 0.15       81,694,000  
 
                               
2007
                               
First Quarter
  $ 61.80     $ 48.28     $ 0.10       44,985,000  
Second Quarter
  $ 77.53     $ 57.83     $ 0.12       45,298,000  
Third Quarter
  $ 80.55     $ 51.61     $ 0.12       54,029,000  
Fourth Quarter
  $ 67.39     $ 45.00     $ 0.12       62,577,000  
As of February 6, 2009, we had approximately 21,500 stockholders, including beneficial owners holding shares in street name.
We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors. Our Credit Agreement limits the payment of dividends. See Note 11 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”
Under our common stock repurchase program, repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. There were no common stock repurchases during the fourth quarter of 2008.

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Item 6. Selected Financial Data
The following table shows our selected financial information as of the dates or for the periods indicated. This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Form 10-K.
                                         
    Years Ended December 31,  
    2008(1)     2007(1)     2006(1)(3)     2005(1)(2)(3)     2004(2)(3)  
    (In thousands, except per share data)  
FINANCIAL DATA
                                       
For the period
                                       
Sales and other revenues
  $ 5,867,668     $ 4,791,742     $ 4,023,217     $ 3,046,313     $ 2,116,245  
Income from continuing operations before income taxes
    185,384       499,444       383,501       263,652       136,929  
Income tax provision
    64,826       165,316       136,603       99,626       53,985  
 
                             
Income from continuing operations
    120,558       334,128       246,898       164,026       82,944  
Income from discontinued operations, net of taxes
                19,668       2,963       935  
 
                             
Net income before cumulative effect of change in accounting principle
    120,558       334,128       266,566       166,989       83,879  
Cumulative effect of accounting change (net of income tax expense of $426)
                      669        
 
                             
 
                                       
Net income
  $ 120,558     $ 334,128     $ 266,566     $ 167,658     $ 83,879  
 
                             
 
                                       
Net income per common share — basic
  $ 2.40     $ 6.09     $ 4.68     $ 2.72     $ 1.34  
 
                                       
Net income per common share — diluted
  $ 2.38     $ 5.98     $ 4.58     $ 2.65     $ 1.30  
 
                                       
Cash dividends declared per common share
  $ 0.60     $ 0.46     $ 0.29     $ 0.19     $ 0.145  
 
                                       
Average number of common shares outstanding:
                                       
Basic
    50,202       54,852       56,976       61,728       62,780  
Diluted
    50,549       55,850       58,210       63,244       64,340  
 
                                       
Net cash provided by operating activities
  $ 155,490     $ 422,737     $ 245,183     $ 251,234     $ 164,604  
Net cash provided by (used for) investing activities
  $ (57,777 )   $ (293,057 )   $ 35,805     $ (320,135 )   $ (194,003 )
Net cash provided by (used for) financing activities
  $ (151,277 )   $ (189,428 )   $ (175,935 )   $ 50,505     $ 85,169  
 
                                       
At end of period
                                       
Cash, cash equivalents and investments in marketable securities
  $ 96,008     $ 329,784     $ 255,953     $ 254,842     $ 219,265  
Working capital
  $ 68,465     $ 216,541     $ 240,181     $ 210,103     $ 159,839  
Total assets
  $ 1,874,225     $ 1,663,945     $ 1,237,869     $ 1,142,900     $ 982,713  
Total debt, including current maturities and borrowings under credit agreements
  $ 370,914     $     $     $     $ 33,572  
Stockholders’ equity
  $ 541,540     $ 593,794     $ 466,094     $ 377,351     $ 339,916  
 
(1)   We reconsolidated HEP effective March 1, 2008 and include the consolidated results of HEP in our financial statements. For the period from July 1, 2005 through February 29, 2008, we accounted for our investment in HEP under the equity method of accounting whereby we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance. Prior to July 1, 2005, HEP was a consolidated entity. See “Company Overview” under Items 1 and 2, “Business and Properties” for information regarding our reconsolidation of HEP effective March 1, 2008.
 
(2)   The average number of shares of common stock and per share amounts have been adjusted to reflect the two-for-one stock split effective June 1, 2006.
 
(3)   On March 31, 2006, we sold our Montana Refinery. Results of operations of the Montana Refinery that were previously reported in operations are now reported in discontinued operations.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Item 7 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of HEP effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.
OVERVIEW
We are principally an independent petroleum refiner operating two refineries in Artesia and Lovington, New Mexico (operated as one refinery) and Woods Cross, Utah. As of December 31, 2008, our refineries had a combined crude capacity of 116,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2008, we also owned a 46% interest in HEP, which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande.
Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel and jet fuel in markets in the southwestern and western United States. Our sales and other revenues and net income for the year ended December 31, 2008 were $5,867.7 million and $120.6 million, respectively. Our sales and other revenues and net income for the year ended December 31, 2007 were $4,791.7 million and $334.1 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the year ended December 31, 2008 were $5,667.3 million, an increase from $4,325.4 million for the year ended December 31, 2007.
On February 29, 2008, we closed on the sale of the Crude Pipelines and Tankage Assets to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.
In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with HEP. Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the PPI, but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the FERC Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a FERC adjustment factor. Additionally, we amended the Omnibus Agreement to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.
HEP is a VIE as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.
On March 31, 2006 we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. We have presented the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale in discontinued operations.

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Under our common stock repurchase program, repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million or an average of $42.48 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.
RESULTS OF OPERATIONS
Financial Data
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands, except per share data)  
Sales and other revenues
  $ 5,867,668     $ 4,791,742     $ 4,023,217  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)
    5,280,699       4,003,488       3,349,404  
Operating expenses (exclusive of depreciation and amortization)
    267,570       209,281       208,460  
General and administrative expenses (exclusive of depreciation and amortization)
    54,906       68,773       63,255  
Depreciation and amortization
    63,789       43,456       39,721  
Exploration expenses, including dry holes
    372       412       486  
 
                 
Total operating costs and expenses
    5,667,336       4,325,410       3,661,326  
 
                 
 
Income from operations
    200,332       466,332       361,891  
Other income (expense):
                       
Equity in earnings of Holly Energy Partners
    2,990       19,109       12,929  
Minority interest in earnings of Holly Energy Partners
    (7,041 )            
Impairment of equity securities
    (3,724 )            
Gain on sale of HPI
    5,958              
Interest income
    10,824       15,089       9,757  
Interest expense
    (23,955 )     (1,086 )     (1,076 )
 
                 
 
    (14,948 )     33,112       21,610  
 
                 
Income from continuing operations before income taxes
    185,384       499,444       383,501  
Income tax provision
    64,826       165,316       136,603  
 
                 
Income from continuing operations
    120,558       334,128       246,898  
Income from discontinued operations, net of taxes
                19,668  
 
                 
Net income
  $ 120,558     $ 334,128     $ 266,566  
 
                 
 
                       
Basic earnings per share:
                       
Continuing operations
  $ 2.40     $ 6.09     $ 4.33  
Discontinued operations
                0.35  
 
                 
Net income
  $ 2.40     $ 6.09     $ 4.68  
 
                 
 
                       
Diluted earnings per share:
                       
Continuing operations
  $ 2.38     $ 5.98     $ 4.24  
Discontinued operations
                0.34  
 
                 
Net income
  $ 2.38     $ 5.98     $ 4.58  
 
                 
 
                       
Cash dividends declared per common share
  $ 0.60     $ 0.46     $ 0.29  
 
                 
 
                       
Average number of common shares outstanding:
                       
Basic
    50,202       54,852       56,976  
Diluted
    50,549       55,850       58,210  

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Balance Sheet Data
                 
    Years Ended December 31,
    2008   2007
    (In thousands)
Cash, cash equivalents and investments in marketable securities
  $ 96,008     $ 329,784  
Working capital
  $ 68,465     $ 216,541  
Total assets
  $ 1,874,225     $ 1,663,945  
Long-term debt — HEP
  $ 341,914     $  
Stockholders’ equity
  $ 541,540     $ 593,794  
Other Financial Data
                         
    Years Ended December 31,
    2008   2007   2006
    (In thousands)
Net cash provided by operating activities
  $ 155,490     $ 422,737     $ 245,183  
Net cash provided by (used for) investing activities
  $ (57,777 )   $ (293,057 )   $ 35,805  
Net cash used for financing activities
  $ (151,277 )   $ (189,428 )   $ (175,935 )
Capital expenditures
  $ 418,059     $ 161,258     $ 120,429  
EBITDA from continuing operations (1)
  $ 262,304     $ 528,897     $ 414,541  
 
(1)   Earnings before interest, taxes, depreciation and amortization, which we refer to as (“EBITDA”), is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. We are reporting EBITDA from continuing operations. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Eliminations.
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
Sales and other revenues
                       
Refining(1)
  $ 5,837,449     $ 4,790,164     $ 4,021,974  
HEP(2)
    101,750              
Corporate and other
    2,641       1,578       1,752  
Eliminations
    (74,172 )           (509 )
 
                 
Consolidated
  $ 5,867,668     $ 4,791,742     $ 4,023,217  
 
                 
 
                       
Operating income (loss)
                       
Refining(1)
  $ 210,252     $ 537,118     $ 425,474  
HEP(2)
    41,734              
Corporate and other
    (51,654 )     (70,786 )     (63,583 )
 
                 
Consolidated
  $ 200,332     $ 466,332     $ 361,891  
 
                 
 
(1)   The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. Although we previously included the Montana Refinery in the Refining segment prior to its sale in March 2006, the results of the Montana Refinery are now included in discontinued operations and are not included in the

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    above tables. The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes Holly Asphalt Company which manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.
 
(2)   The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through their pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at their storage tanks and terminals. The HEP segment also includes a 70% interest in Rio Grande which also provides petroleum products transportation services. Revenues from the HEP segment are earned through transactions for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande.
Refining Operating Data
Our refinery operations include the Navajo Refinery and the Woods Cross Refinery. The following tables set forth information, including non-GAAP performance measures about our consolidated refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
                         
    Years Ended December 31,  
    2008     2007     2006  
Consolidated (8)
                       
Crude charge (BPD) (1)
    100,680       103,490       96,570  
Refinery production (BPD) (2)
    110,850       113,270       105,730  
Sales of produced refined products (BPD)
    111,950       115,050       105,090  
Sales of refined products (BPD) (3)
    120,750       126,800       119,870  
 
                       
Refinery utilization (4)
    89.7 %     94.1 %     92.4 %
 
                       
Average per produced barrel (5)
                       
Net sales
  $ 108.83     $ 89.77     $ 80.21  
Cost of products (6)
    97.87       73.03       64.43  
 
                 
Refinery gross margin
    10.96       16.74       15.78  
Refinery operating expenses (7)
    5.14       4.43       4.83  
 
                 
Net operating margin
  $ 5.82     $ 12.31     $ 10.95  
 
                 
 
(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 101,000 BPSD to 109,000 BPSD during 2006, from 109,000 BPSD to 111,000 BPSD in mid-year 2007 and by an additional 5,000 BPSD in the fourth quarter of 2008, increasing our consolidated crude capacity to 116,000 BPSD.
 
(5)   Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
(6)   Transportation costs billed from HEP are included in cost of products.
 
(7)   Represents operating expenses of the refineries, exclusive of depreciation and amortization.
 
(8)   The Montana Refinery was sold on March 31, 2006. Amounts reported are for the Navajo and Woods Cross Refineries.

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Results of Operations — Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Summary
Net Income for the year ended December 31, 2008 was $120.6 million ($2.40 per basic and $2.38 per diluted share) compared to $334.1 million ($6.09 per basic and $5.98 per diluted share) for the year ended December 31, 2007. Net income for the year ended December 31, 2008 decreased $213.5 million compared to the year ended December 31, 2007 due principally to reduced refined product margins during the first half of 2008. Overall refinery gross margins from continuing operations for the year ended December 31, 2008 were $10.96 per produced barrel compared to $16.74 for the year ended December 31, 2007.
Sales and Other Revenues
Sales and other revenues from continuing operations increased 23% from $4,791.7 million for the year ended December 31, 2007 to $5,867.7 million for the year ended December 31, 2008 due principally to higher refined product sales prices, partially offset by a 5% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold increased 21% from $89.77 for the year ended December 31, 2007 to $108.83 for the year ended December 31, 2008. The decrease in volumes of refined products sold was principally due to the effects of downtime at our refineries during the second quarter and a scheduled major maintenance turnaround at our Woods Cross Refinery during the third quarter of 2008. Additionally, sales and other revenues for the year ended December 31, 2008 include $27.6 million in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties due to our reconsolidation of HEP effective March 1, 2008. Sales and other revenues for 2007 include $23.0 million in sulfur credit sales.
Cost of Products Sold
Cost of products sold increased 32% from $4,003.5 million in 2007 to $5,280.7 million in 2008 due principally to significantly higher crude oil costs in the first half of 2008. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 34% from $73.03 in 2007 to $97.87 in 2008. This increase was partially offset by the effects of a 5% decrease in year-over-year volumes of refined products sold.
Gross Refinery Margins
Gross refining margin per produced barrel decreased 35% from $16.74 in 2007 to $10.96 in 2008 due to an increase in the average we paid per produced barrel of crude oil and feedstocks, partially offset by the effects of an increase in the average sales price we received per produced barrel sold. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 28% from $209.3 million in 2007 to $267.6 million in 2008 due principally to the inclusion of $35.2 million in operating costs attributable to HEP as a result of our reconsolidation effective March 1, 2008. Additionally, higher refinery utility and payroll costs along with increased maintenance costs associated with unplanned downtime contributed to this increase.
General and Administrative Expenses
General and administrative expenses decreased 20% from $68.8 million in 2007 to $54.9 million in 2008 due principally to a decrease in equity-based compensation expense which is to some extent affected by our stock price. Additionally, general and administrative expenses for 2008 include $5.6 million in expenses related to HEP operations following our reconsolidation of HEP effective March 1, 2008.
Depreciation and Amortization Expenses
Depreciation and amortization increased 47% from $43.5 million in 2007 to $63.8 million in 2008 due principally to the inclusion of $19.2 million in depreciation and amortization related to HEP operations following our reconsolidation of HEP effective March 1, 2008 and depreciation attributable to capitalized refinery improvement projects in 2008 and 2007.

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Equity in Earnings of HEP
Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP was $3.0 million and $19.1 million for the years ended December 31, 2008 and 2007, respectively.
Minority Interests
Minority interests in income for the year ended December 31, 2008 reduced our income by $7.0 million and represents the noncontrolling interest in HEP’s earnings.
Impairment of equity securities
Impairment of equity securities represents an impairment loss of $3.7 million during the year ended December 31, 2008 that relates to 1,000,000 shares of Connacher common stock that was received in connection with our sale of the Montana Refinery in 2006 and we accounted for this as an other-than-temporary decline in the fair value of these securities.
Gain on sale of HPI
We sold substantially all of the oil and gas properties of HPI, a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6.0 million, resulting in a gain of $6.0 million.
Interest Income
Interest income for the year ended December 31, 2008 was $10.8 million compared to $15.1 million for the year ended December 31, 2007 due principally to the effects of a lower interest rate environment combined with a decrease in investments in marketable debt securities.
Interest Expense
Interest expense was $24.0 million for the year ended December 31, 2008 compared to $1.1 million for the year ended December 31, 2007. The increase in interest expense was due principally to the inclusion of $21.5 million in interest expense related to HEP operations following our reconsolidation of HEP effective March 1, 2008.
Income Taxes
Income taxes decreased 61% from $165.3 million in 2007 to $64.8 million in 2008 due to lower pre-tax earnings in 2008 compared to 2007. The effective tax rate for the year ended December 31, 2008 was 35.0% compared to 33.1% for the year ended December 31, 2007. We realized a lower effective tax rate during 2007 due principally to a higher utilization of ULSD tax credits in 2007 that were fully utilized in 2008.
Results of Operations — Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Summary
Income from continuing operations for the year ended December 31, 2007 was $334.1 million ($6.09 per basic and $5.98 per diluted share) compared to $246.9 million ($4.33 per basic and $4.24 per diluted share) for the year ended December 31, 2006. Net income from continuing operations increased by 35% or $87.2 million for the year ended December 31, 2007 compared to the year ended December 31, 2006 due principally to an overall increase in refined product margins during the first half of 2007 combined with an increase in volumes of produced refined products sold, partially offset by an increase in total operating costs and expenses and an overall decrease in refined product margins during the second half of the year. Overall sales of produced refined products from continuing operations for the year ended December 31, 2007 increased 9% compared to the year ended December 31, 2006. Overall refinery gross margins from continuing operations for the year ended December 31, 2007 were $16.74 per produced barrel compared to $15.78 for the year ended December 31, 2006.
Sales and Other Revenues
Sales and other revenues from continuing operations increased 19% from $4,023.2 million for the year ended December 31, 2006 to $4,791.7 million for the year ended December 31, 2007 due principally to higher refined product sales prices and an increase in volumes of produced refined products sold. The average sales price we received per produced barrel sold increased 12% from $80.21 for the year ended December 31, 2006 to $89.77 for

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the year ended December 31, 2007. The total volume of produced refined products sold increased 9% for the year ended December 31, 2007 compared to the same period in 2006 due principally to an increase in production following a combined 10,000 BPSD capacity expansion at our Navajo Refinery during 2006 and 2007. Additionally, sales and other revenues for the year ended December 31, 2007 include $23.0 million in sulfur credit sales compared to $15.9 million for the year ended December 31, 2006.
Cost of Products Sold
Cost of products sold increased 20% from $3,349.4 million in 2006 to $4,003.5 million in 2007 due principally to the higher costs of purchased crude oil and an increase in volumes of produced refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 13% from $64.43 in 2006 to $73.03 in 2007.
We recognized a $0.8 million charge to cost of products sold during 2007 resulting from liquidations of certain LIFO inventory quantities that were carried at higher costs as compared to current costs. In 2006, we recognized a $4.2 million reduction to cost of products sold as liquidated LIFO inventory quantities were carried at lower costs as compared to then current costs.
Refinery Gross Margin
Refining gross margin per produced barrel increased 6% from $15.78 in 2006 to $16.74 in 2007. Refinery gross margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased less than 1% from $208.5 million in 2006 to $209.3 million in 2007.
General and Administrative Expenses
General and administrative expenses increased 9% from $63.3 million in 2006 to $68.8 million in 2007 due principally to increased equity-based incentive compensation expense and software implementation costs.
Depreciation and Amortization Expenses
Depreciation and amortization increased 9% from $39.7 million in 2006 to $43.5 million in 2007 due to capitalized refinery improvement projects in 2006 and 2007.
Equity in Earnings of HEP
Our equity in earnings of HEP was $19.1 million for the year ended December 31, 2007 compared to $12.9 million for the year ended December 31, 2006. The increase in our equity in earnings of HEP was due principally to an increase in HEP’s earnings for the year ended December 31, 2007 compared to the year ended December 31, 2006.
Interest Income
Interest income for the year ended December 31, 2007 was $15.1 million compared to $9.8 million for the year ended December 31, 2006. The increase in interest income was due principally to the effects of a higher interest rate environment combined with increased investments in marketable debt securities.
Interest Expense
Interest expense was $1.1 million for each of the years ended December 31, 2007 and 2006.
Income Taxes
Income taxes increased 21% from $136.6 million in 2006 to $165.3 million in 2007 due to higher pre-tax earnings in 2007 compared to 2006, partially offset by a lower effective tax rate. The effective tax rate for the year ended December 31, 2007 was 33.1% compared to 35.6% for the year ended December 31, 2006. The decrease in our effective tax rate was due principally to a statutory increase from 3% to 6% in the federal tax deduction for domestic manufacturing activities.

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Discontinued Operations
We had no income from discontinued operations for the year ended December 31, 2007, as our Montana Refinery operations have ceased. Income from discontinued operations was $19.7 million for the year ended December 31, 2006 which consisted of a $14.0 million gain on the sale of the Montana Refinery, net of $8.3 million in income taxes, and $5.7 million of earnings which was largely due to the liquidation of certain retained quantities of inventories that were not included in the sale of our Montana Refinery on March 31, 2006.
LIQUIDITY AND CAPITAL RESOURCES
We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value, and are invested primarily in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings. We also invest available cash in highly-rated marketable debt securities primarily issued by government entities that have maturities greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly and may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of December 31, 2008, we had cash and cash equivalents of $40.8 million, marketable securities with maturities under one year of $49.2 million and marketable securities with maturities greater than one year, but less than two years, of $6.0 million.
Cash and cash equivalents decreased by $53.6 million during 2008. The combined cash used for investing and financing activities of $57.8 million and $151.3 million, respectively, exceeded cash provided by operating activities of $155.5 million. Working capital decreased by $148.1 million during 2008. This decrease was due principally to a reduction in cash, cash equivalents and short-term investments in marketable securities resulting from increased capital expenditures and miscellaneous year-over-year changes in collections and payments.
In March 2008, we entered into an amended and restated $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America as administrative agent and lender. The Credit Agreement has a term of five years and an option to increase the facility to $300.0 million subject to certain conditions. This credit facility expires in 2013 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2008. At December 31, 2008, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.5 million at December 31, 2008.
There are currently a total of nine lenders under our $175.0 million Credit Agreement with individual commitments ranging from $15.0 million to $27.5 million. If any particular lender could not honor its commitment, we believe the unused capacity under our Credit Agreement, which is $172.5 million as of December 31, 2008, would be available to meet our borrowing needs. Additionally, we have reviewed publicly available information on our lenders in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We have not experienced, nor do we expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.
HEP has a $300.0 million senior secured revolving credit agreement (the “HEP Credit Agreement”) with Union Bank of California, N.A. as one of the lenders and as administrative agent and an option to increase the facility to $370.0 million subject to certain conditions. The HEP Credit Agreement expires in August 2011 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general partnership purposes. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included in our Consolidated Balance Sheets at December 31, 2008 consist of $5.3 million in cash and cash equivalents, $5.1 million in trade accounts receivable and other current assets, $354.1 million in property, plant and

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equipment, net and $56.1 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement.
There are currently a total of thirteen lenders under the HEP Credit Agreement with individual commitments ranging from $15.0 million to $40.0 million. If any particular lender could not honor its commitment, HEP has unused capacity available under their credit agreement, which was $100.0 million as of December 31, 2008, to meet their borrowing needs. Additionally, publicly available information on these lenders is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the credit agreement. HEP has not experienced, nor do they expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, HEP believes there would be alternative lenders or options available.
The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service on up to $35.0 million of the principal amount of the HEP Senior Notes.
At December 31, 2008, the carrying amount of HEP’s long-term debt was as follows:
         
    (In thousands)  
HEP Credit Agreement
  $ 200,000  
 
       
HEP Senior Notes
       
Principal
    185,000  
Unamortized discount
    (16,223 )
Unamortized premium — de-designated fair value hedge
    2,137  
 
     
 
    170,914  
 
     
 
       
Total debt
    370,914  
Less short-term borrowings under HEP Credit Agreement
    29,000  
 
     
 
       
Total long-term debt
  $ 341,914  
 
     
See “Risk Management” for a discussion of HEP’s interest rate swaps.
Under our common stock repurchase program, repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million or an average of $42.48 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.
We believe our current cash, cash equivalents and marketable securities, along with future internally generated cash flow and funds available under our credit facilities provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends and distributions by HEP to its minority interest holders. In addition, components of our growth strategy

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may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.
Cash Flows — Operating Activities
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Net cash flows provided by operating activities were $155.5 million for the year ended December 31, 2008 compared to $422.7 million for the year ended December 31, 2007, a decrease of $267.2 million. Net income for 2008 was $120.6 million, a decrease of $213.5 million from $334.1 million for 2007. Additionally, the non-cash items of depreciation and amortization, deferred taxes, equity-based compensation, gain on the sale of HPI and non-cash interest resulting from changes in the fair value of two of HEP’s interest rate swaps, resulted in an increase to operating cash flows of $104.2 million for the year ended December 31, 2008 compared to $76.5 million for the year ended December 31, 2007. Distributions in excess of equity in earnings of HEP decreased to $3.1 million for the year ended December 31, 2008 compared to $3.7 million for the year ended December 31, 2007. Working capital items decreased cash flows by $37.0 million in 2008 compared to an increase of $15.0 million in 2007. For the year ended December 31, 2008, inventories decreased by $15.0 million compared to an increase of $11.0 million for 2007. Also for 2008, accounts receivable decreased by $332.0 million compared to an increase of $216.3 million for 2007 and accounts payable decreased by $393.2 million compared to an increase of $264.2 million for 2007. Additionally, for 2008, turnaround expenditures were $34.8 million compared to $2.7 million for 2007.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Net cash flows provided by operating activities were $422.7 million for 2007 compared to $245.2 million for 2006, an increase of $177.5 million. Net income in 2007 was $334.1 million, an increase of $67.5 million from net income of $266.6 million for 2006. The non-cash items of depreciation and amortization, deferred taxes, equity-based compensation and gain on sale of assets resulted in an increase to operating cash flows of $76.5 million for the year ended December 31, 2007 compared to $31.4 million for the year ended December 31, 2006. Distributions in excess of equity in earnings of HEP decreased to $3.7 million for the year ended December 31, 2007 compared to $7.4 million for the year ended December 31, 2006. Working capital items increased cash flows by $15.0 million in 2007 compared to a decrease of $40.9 million in 2006. For the year ended December 31, 2007, inventories increased by $11.0 million compared to an increase of $33.8 million for the year ended December 31, 2006. Also for 2007, accounts receivable increased by $216.3 million compared to a decrease of $12.1 million for 2006 and accounts payable increased by $264.2 million compared to a decrease of $26.4 million for 2006. Additionally, for 2007, turnaround expenditures were $2.7 million compared to $11.6 million for 2006.
Cash Flows — Investing Activities and Planned Capital Expenditures
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Net cash flows used for investing activities were $57.8 million for 2008 compared to $293.1 million for 2007, a decrease of $235.3 million. Cash expenditures for property, plant and equipment for 2008 totaled $418.1 million compared to $161.3 million for 2007. Capital expenditures for the year ended December 31, 2008 include $34.3 million attributable to HEP. Also, in 2008 we invested $769.1 million in marketable securities and received proceeds of $945.5 million from the sales and maturities of marketable securities. Additionally for the year ended December 31, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP on February 29, 2008. We are also presenting HEP’s March 1, 2008 cash balance of $7.3 million as an inflow as a result of our reconsolidation of HEP effective March 1, 2008. For the year ended December 31, 2007, we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities of marketable securities.

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Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Net cash flows used for investing activities were $293.1 million for 2007 compared to net cash flows provided by investing activities of $35.8 million for 2006, a decrease of $328.9 million. Cash expenditures for property, plant and equipment for 2007 totaled $161.3 million compared to $120.4 million for 2006. Also, in 2007 we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities of marketable securities. For the year ended December 31, 2006, we invested $212.0 million in marketable securities and received proceeds of $319.3 million from sales and maturities of marketable securities. Furthermore in 2006, we received cash proceeds of $48.9 million following the sale of our Montana Refinery on March 31, 2006.
Planned Capital Expenditures
Holly Corporation
Each year our Board of Directors approves in our annual capital budget capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total new capital budget for 2009 is approximately $19.8 million, not including the capital projects approved in prior years, and our expansion and feedstock flexibility projects at the Navajo and Woods Cross refineries, as described below. The 2009 capital budget is comprised of $11.4 million for refining improvement projects for the Navajo Refinery, $5.3 million for projects at the Woods Cross Refinery, $0.4 million for marketing-related projects, $1.4 million for asphalt plant projects and $1.3 million for other miscellaneous projects.
At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum units. Phase I is expected to be mechanically complete in the first quarter of 2009 and was originally estimated to cost $163.0 million. The total cost of phase I is now expected to be approximately $185.0 million. The added costs are associated with permit timing delays, scope changes due to permit required pollution control equipment that was not anticipated, material cost escalation and increased labor rates.
Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 and was originally estimated to cost $84.0 million. The total cost of phase II is now expected to be approximately $96.0 million. The added costs are associated with better scope definition on the Artesia crude and vacuum unit revamp portion of the overall project and material cost escalation.
We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $15.0 million and are expected to be completed at the same time as the phase II project.
The Navajo Refinery is also installing a new 100 ton per day sulfur recovery unit that is scheduled for mechanical completion early in the first quarter of 2009. The project was originally estimated to cost $26.0 million and is now projected to cost $31.0 million. The added costs are associated permit delays, material cost escalation and increased labor rates.
Once the Navajo projects discussed above are complete, the Navajo Refinery will be able to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt with all their performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks and enable the refinery to meet new LSG specifications required by the EPA.

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At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipment and black wax unloading systems. The total cost of this project was approximately $122.0 million versus our original $105.0 million estimate. Increased costs resulted from offsite scope additions, material cost escalation and increased labor rates. The projects were completed in the fourth quarter of 2008. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.
To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. HEP’s joint venture pipeline with Plains will permit the transportation of additional crude oil into the Salt Lake City area. HEP’s joint venture project with Plains is further described under the HEP section of this discussion of planned capital expenditures.
In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas. Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million, with our share of the cost totaling $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered into an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum. Additionally in 2008, we purchased a terminal and rail facility located near Cedar City, Utah that will serve as a key component of our UNEV joint venture pipeline.
The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.
In July 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion’s pipeline from Cushing, Oklahoma to its Slaughter Station located in west Texas. Our Board of Directors has approved capital expenditures of up to $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico and a 65-mile pipeline from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline project that connects HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. Under the provisions of the Omnibus Agreement with HEP, HEP will have an option to purchase these transportation assets upon our completion of these projects. We expect to complete these projects in the fourth quarter of 2009.
In 2009, we expect to spend approximately $350.0 million on currently approved capital projects, including sustaining capital and turnaround costs. This amount consists of certain carryovers of capital projects from previous years, less carryovers to subsequent years of certain of the currently approved capital projects.
In October 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act provided an immediate deduction of 75% of certain costs paid or incurred to comply with the ULSD standards, and a tax credit based on ULSD production of up to 25% of those costs. In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act created tax incentives for refiners by providing for an immediate deduction of 50% of certain refinery capacity expansion costs when the expansion assets are placed in service. We believe the capacity expansion projects at the Navajo and Woods Cross Refineries qualify for this deduction.

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The above mentioned regulatory compliance items, including the ULSD and LSG requirements, or other presently existing or future environmental regulations could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements.
HEP
Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in their current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2009 HEP capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of the South System and the joint venture with Plains discussed below.
In October 2007, we amended the HEP PTA under which HEP has agreed to expand their South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at HEP’s El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. HEP expects to complete the majority of this project in early 2009.
In November 2007, HEP executed a definitive agreement with Plains to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by HEP. HEP expects to purchase their 25% interest in the joint venture in March 2009 when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including our Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah that is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of HEP’s investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to us upon the closing of their investment in the SLC Pipeline.
HEP is currently working on a capital improvement project that will provide increased flexibility and capacity to their intermediate pipelines enabling them to accommodate increased volumes following the completion of our Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $5.1 million.
Also, HEP is currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline at an estimated cost of $1.9 million for completion in early 2009.
Cash Flows — Financing Activities
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Net cash flows used for financing activities were $151.3 million for 2008 compared to $189.4 million for 2007, a decrease of $38.1 million. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29.0 million under the HEP Credit Agreement and purchased $0.8 million in HEP common units in the open market for restricted unit grants. Additionally in 2008, we paid an aggregate of $0.9 million in deferred financing costs related to our amended and restated Credit Agreement and the HEP Credit Agreement. Under our common stock repurchase program, we purchased treasury stock of $151.1 million in 2008. We also paid $29.1 million in dividends, received a $17.0 million contribution from our UNEV Pipeline joint venture partner, received $1.0 million for common stock issued upon exercise of stock options and recognized $5.7 million in excess tax benefits on our equity based compensation during 2008. Also during this period, HEP paid $22.1 million in distributions to its minority interest holders. During 2007, we purchased treasury stock of $207.2 million under our

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stock repurchase program, paid $23.2 million in dividends, received $2.3 million for common stock issued upon exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Net cash flows used for financing activities were $189.4 million for 2007 compared to $175.9 million for 2006, an increase of $13.5 million. Under our common stock repurchase program, we purchased treasury stock of $207.2 million in 2007. We also paid $23.2 million in dividends, received $2.3 million for common stock issued upon exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation during 2007. During 2006, we purchased treasury stock of $175.4 million under our stock repurchase program, paid $15.0 million in dividends, received $2.6 million for common stock issued upon exercise of stock options and recognized $11.8 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.
Contractual Obligations and Commitments
The following table presents our long-term contractual obligations as of December 31, 2008 in total and by period due beginning in 2009. Effective March 1, 2008, we reconsolidated HEP. As a result, the table below does not include our contractual obligations to HEP under our three long-term transportation agreements with HEP. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2. “Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.
                                         
            Payments Due by Period  
            Less than                     Over  
Contractual Obligations(3)(4)   Total     1 Year     2-3 Years     4-5 Years     5 Years  
    (In thousands)  
Holly Corporation
                                       
Operating leases
  $ 6,062     $ 2,461     $ 3,327     $ 190     $ 84  
Hydrogen supply agreement(1)
    91,570       6,315       12,630       12,630       59,995  
Other service agreements(2)
    13,953       2,371       3,970       3,857       3,755  
 
                             
 
                                       
 
    111,585       11,147       19,927       16,677       63,834  
 
                                       
Holly Energy Partners
                                       
Long-term debt — principal(5)
    356,000             171,000             185,000  
Long-term debt — interest(6)
    85,240       15,344       29,427       23,125       17,344  
Pipeline operating and right of way leases
    54,473       6,364       12,709       12,645       22,755  
Other agreements
    23,049       5,221       5,178       4,600       8,050  
 
                             
 
                                       
 
    518,762       26,929       218,314       40,370       233,149  
 
                             
 
                                       
Total
  $ 630,347     $ 38,076     $ 238,241     $ 57,047     $ 296,983  
 
                             
 
(1)   We have entered into a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices over a fifteen year period commencing July 1, 2008. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term. We have estimated the future payments in the table above using current market rates. Therefore, actual amounts expended for this obligation in the future could vary significantly from the amounts presented above.
 
(2)   Includes: $13.4 million for transportation of natural gas and feedstocks to our refineries under contracts expiring in 2015 and 2016; and various service contracts with expiration dates through 2011.
 
(3)   Amounts shown do not include obligations under crude oil transportation agreements providing that we will ship quantities of crude oil with each agreement having initial terms of 10 years. Our obligations under these agreements are subject to certain conditions including completion of construction and expansion projects by the transportation companies. Our shipping commitments shall begin upon

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      completion of these projects which we expect to begin in the fourth quarter of 2009 with the remaining commitments to be phased in through the first quarter of 2011. In addition, amounts shown do not include our 10-year commitment to ship on the UNEV Pipeline, in which we own a 75% interest, an annual average of 15,000 barrels per day of refined products at an agreed tariff. Our commitment to ship on the UNEV Pipeline will begin with the completion of the pipeline.
 
  (4)   We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits of $4.4 million as of December 31, 2008, have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 12 to the Consolidated Financial Statements.
 
  (5)   HEP’s long-term debt consists of the $185.0 million principal balance on the HEP Senior Notes and $171.0 million of outstanding principal under the HEP Credit Agreement that has been classified as long-term debt.
 
  (6)   Interest payments consist of interest on HEP’s 6.25% Senior Notes and interest on long-term debt under the HEP Credit Agreement. Interest under the credit agreement debt is based on the effective interest rate of 2.21% at December 31, 2008.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows. For additional information, see Note 1 to the Consolidated Financial Statements “Description of Business and Summary of Significant Accounting Policies.”
Inventory Valuation
Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2008, our LIFO inventory layers were valued at historical costs that were established in years when price levels were generally lower; therefore, our results of operation are less sensitive to current market price reductions. As of December 31, 2008, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $33.0 million. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.
Deferred Maintenance Costs
Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require routine “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. In order to minimize downtime during turnarounds, we utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit.

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Long-lived Assets
We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2008, 2007 and 2006.
Variable Interest Entity
HEP is a variable interest entity as defined under Financial Accounting Standards Board Interpretation No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.
Contingencies
We are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters.
New Accounting Pronouncements
Statement of Financial Accounting Standard (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51” In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. This standard is effective as of January 1, 2009. As a result, our minority interest balance will be reclassified as a component of “Stockholders’ equity” in our consolidated balance sheets. At December 31, 2008, our minority interest balance was $394.8 million.
SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133” In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. This standard is effective as of January 1, 2009 and will not have a material impact on our financial condition, results of operations and cash flows.
RISK MANAGEMENT
We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit. Our profitability depends largely on the spread between market prices for refined products

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and market prices for crude oil. A substantial or prolonged reduction in this spread could have a significant negative effect on our earnings, financial condition and cash flows.
As of December 31, 2008, HEP had three interest rate swap contracts.
HEP entered into an interest rate swap to hedge their exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that HEP used to finance their purchase of the Crude Pipelines and Tankage Assets from us. This interest rate swap effectively converts their $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2008. The maturity date of this swap contract is February 28, 2013. HEP intends to renew the HEP Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.
HEP designated this interest rate swap as a cash flow hedge. Based on their assessment of effectiveness using the change in variable cash flows method, HEP determined that this interest rate swap is effective in offsetting the variability in interest payments on the $171.0 million variable rate debt resulting from changes in the London Interbank Offered Rate (“LIBOR”). Under hedge accounting, HEP adjusts their cash flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, HEP measures hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of the swap against the expected future interest payments on the $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008, HEP had no ineffectiveness on their cash flow hedge.
HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36% as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.
In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of their hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.
HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with a corresponding entry to interest expense. For the year ended December 31, 2008, HEP recognized $2.3 million in interest expense attributable to fair value adjustments to its interest rate swaps.
Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the HEP Senior Notes. This hedge met the requirements to assume no ineffectiveness and was accounted for using the “shortcut” method of accounting whereby offsetting fair value adjustments to the underlying swap were made to the carrying value of the HEP Senior Notes, effectively adjusting the carrying value of this $60.0 million to its fair value. HEP de-designated this hedge in October 2008. At this time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.
HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.

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Additional information on HEP’s interest rate swaps is as follows:
                         
    Balance Sheet           Location of    
Interest Rate Swaps   Location   Fair Value   Offsetting Balance   Offsetting Amount
                (In thousands)        
Asset
                       
Fixed-to-variable interest rate swap - $60 million of 6.25% Senior Notes
  Other assets   $ 4,079     Long-term debt
Interest expense
  $ (2,195
(1,884
)
)
 
                       
 
                       
 
      $ 4,079         $ (4,079 )
 
                       
Liability
                       
Cash flow hedge - $171 million LIBOR based debt
  Other long-term
liabilities
  $ (12,967 )   Accumulated other
comprehensive income
  $ 12,967  
Variable-to-fixed interest rate swap - $60 million
  Other long-term
liabilities
    (4,166 )   Interest expense     4,166  
 
                       
 
                       
 
      $ (17,133 )       $ 17,133  
 
                       
We have reviewed publicly available information on our counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. We have not, nor do we expect to experience any difficulty in the counterparties honoring their respective commitments.
We invest a substantial portion of available cash 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. We also invest the remainder of available cash in portfolios of highly rated marketable debt securities, primarily issued by government entities, that have an average remaining duration (including any cash equivalents invested) of not greater than one year and hence the interest rate market risk implicit in these investments is also low. A hypothetical 10% change in the market interest rate over the next year would not materially impact our earnings, cash flow or financial condition since any borrowings under the credit facilities and our investments are at market rates and interest on borrowings and cash investments has historically not been significant as compared to our total operations.
Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
We have formed a risk management oversight committee that is made up of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.

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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 EBITDA to amounts reported under generally accepted accounting principles in financial statements.
Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. We are reporting EBITDA only from continuing operations.
Set forth below is our calculation of EBITDA from continuing operations.
                         
    Years Ended December 31,  
    2008     2007     2006  
            (In thousands)          
Income from continuing operations
  $ 120,558     $ 334,128     $ 246,898  
Add provision for income tax
    64,826       165,316       136,603  
Add interest expense
    23,955       1,086       1,076  
Subtract interest income
    (10,824 )     (15,089 )     (9,757 )
Add depreciation and amortization
    63,789       43,456       39,721  
 
                 
EBITDA from continuing operations
  $ 262,304     $ 528,897     $ 414,541  
 
                 
Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally accepted accounting principles in financial statements.
Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis.
We calculate refinery gross margin and net operating margin using net sales, cost of products and operating expenses, in each case averaged per produced barrel sold. These two margins do not include the effect of depreciation and amortization. Each of these component performance measures can be reconciled directly to our Consolidated Statements of Income.
Other companies in our industry may not calculate these performance measures in the same manner.

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Refinery Gross Margin
Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Refinery gross margin for each of our refineries and for both of our refineries on a consolidated basis is calculated as shown below.
                         
    Years Ended December 31,  
    2008     2007     2006  
Average per produced barrel:
                       
 
                       
Navajo Refinery
                       
Net sales
  $ 108.52     $ 89.68     $ 79.62  
Less cost of products
    98.97       74.10       64.25  
 
                 
Refinery gross margin
  $ 9.55     $ 15.58     $ 15.37  
 
                 
 
                       
Woods Cross Refinery
                       
Net sales
  $ 110.07     $ 90.09     $ 82.09  
Less cost of products
    93.47       69.40       64.99  
 
                 
Refinery gross margin
  $ 16.60     $ 20.69     $ 17.10  
 
                 
 
                       
Consolidated
                       
Net sales
  $ 108.83     $ 89.77     $ 80.21  
Less cost of products
    97.87       73.03       64.43  
 
                 
Refinery gross margin
  $ 10.96     $ 16.74     $ 15.78  
 
                 
Net Operating Margin
Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. Net operating margin for each of our refineries and for both of our refineries on a consolidated basis is calculated as shown below.
                         
    Years Ended December 31,  
    2008     2007     2006  
Average per produced barrel:
                       
 
                       
Navajo Refinery
                       
Refinery gross margin
  $ 9.55     $ 15.58     $ 15.37  
Less refinery operating expenses
    4.58       4.30       4.74  
 
                 
Net operating margin
  $ 4.97     $ 11.28     $ 10.63  
 
                 
 
                       
Woods Cross Refinery
                       
Refinery gross margin
  $ 16.60     $ 20.69     $ 17.10  
Less refinery operating expenses
    7.42       4.86       5.13  
 
                 
Net operating margin
  $ 9.18     $ 15.83     $ 11.97  
 
                 
 
                       
Consolidated
                       
Refinery gross margin
  $ 10.96     $ 16.74     $ 15.78  
Less refinery operating expenses
    5.14       4.43       4.83  
 
                 
Net operating margin
  $ 5.82     $ 12.31     $ 10.95  
 
                 

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Below are reconciliations to our Consolidated Statements of Income for (i) net sales, cost of products and operating expenses, in each case averaged per produced barrel sold, and (ii) net operating margin and refinery gross margin. Due to rounding of reported numbers, some amounts may not calculate exactly.
Reconciliations of refined product sales from produced products sold to total sales and other revenues
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Navajo Refinery
                       
Average sales price per produced barrel sold
  $ 108.52     $ 89.68     $ 79.62  
Times sales of produced refined products sold (BPD)
    89,580       88,920       79,940  
Times number of days in period
    366       365       365  
 
                 
Refined product sales from produced products sold
  $ 3,557,967     $ 2,910,636     $ 2,323,160  
 
                 
 
                       
Woods Cross Refinery
                       
Average sales price per produced barrel sold
  $ 110.07     $ 90.09     $ 82.09  
Times sales of produced refined products sold (BPD)
    22,370       26,130       25,150  
Times number of days in period
    366       365       365  
 
                 
Refined product sales from produced products sold
  $ 901,189     $ 859,229     $ 753,566  
 
                 
 
                       
Sum of refined product sales from produced products sold from our two refineries (4)
  $ 4,459,156     $ 3,769,865     $ 3,076,726  
Add refined product sales from purchased products and rounding (1)
    384,073       383,396       480,641  
 
                 
Total refined products sales
    4,843,229       4,153,261       3,557,367  
Add direct sales of excess crude oil(2)
    860,642       491,150       323,002  
Add other refining segment revenue (3)
    133,578       145,753       141,605  
 
                 
Total refining segment revenue
    5,837,449       4,790,164       4,021,974  
Add HEP segment sales and other revenues
    101,750              
Add corporate and other revenues
    2,641       1,578       1,752  
Subtract consolidations and eliminations
    (74,172 )           (509 )
 
                 
Sales and other revenues
  $ 5,867,668     $ 4,791,742     $ 4,023,217  
 
                 
 
(1)   We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
 
(2)   We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.
 
(3)   Other refining segment revenue includes the incremental revenues associated with Holly Asphalt Company and revenue derived from feedstock and sulfur credit sales.
 
(4)   The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Average sales price per produced barrel sold
  $ 108.83     $ 89.77     $ 80.21  
Times sales of produced refined products sold (BPD)
    111,950       115,050       105,090  
Times number of days in period
    366       365       365  
 
                 
Refined product sales from produced products sold
  $ 4,459,156     $ 3,769,865     $ 3,076,726  
 
                 

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Reconciliation of average cost of products per produced barrel sold to total cost of products sold
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Navajo Refinery
                       
Average cost of products per produced barrel sold
  $ 98.97     $ 74.10     $ 64.25  
Times sales of produced refined products sold (BPD)
    89,580       88,920       79,940  
Times number of days in period
    366       365       365  
 
                 
Cost of products for produced products sold
  $ 3,244,858     $ 2,404,975     $ 1,874,693  
 
                 
 
                       
Woods Cross Refinery
                       
Average cost of products per produced barrel sold
  $ 93.47     $ 69.40     $ 64.99  
Times sales of produced refined products sold (BPD)
    22,370       26,130       25,150  
Times number of days in period
    366       365       365  
 
                 
Cost of products for produced products sold
  $ 765,278     $ 661,899     $ 596,592  
 
                 
 
                       
Sum of cost of products for produced products sold from our two refineries (4)
  $ 4,010,136     $ 3,066,874     $ 2,471,285  
Add refined product costs from purchased products sold and rounding (1)
    389,944       374,432       473,903  
 
                 
Total refined cost of products sold
    4,400,080       3,441,306       2,945,188  
Add crude oil cost of direct sales of excess crude oil(2)
    853,360       492,222       323,337  
Add other refining segment cost of products sold (3)
    101,144       69,960       81,388  
 
                 
Total refining segment cost of products sold
    5,354,584       4,003,488       3,349,913  
Subtract consolidations and eliminations
    (73,885 )           (509 )
 
                 
Cost of products sold (exclusive of depreciation and amortization)
  $ 5,280,699     $ 4,003,488     $ 3,349,404  
 
                 
 
(1)   We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
 
(2)   We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.
 
(3)   Other refining segment cost of products sold includes the cost of products for Holly Asphalt Company and costs attributable to feedstock and sulfur credit sales.
 
(4)   The above calculations of cost of products for produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Average cost of products per produced barrel sold
  $ 97.87     $ 73.03     $ 64.43  
Times sales of produced refined products sold (BPD)
    111,950       115,050       105,090  
Times number of days in period
    366       365       365  
 
                 
Cost of products for produced products sold
  $ 4,010,136     $ 3,066,874     $ 2,471,285  
 
                 

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Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Navajo Refinery
                       
Average refinery operating expenses per produced barrel sold
  $ 4.58     $ 4.30     $ 4.74  
Times sales of produced refined products sold (BPD)
    89,580       88,920       79,940  
Times number of days in period
    366       365       365  
 
                 
Refinery operating expenses for produced products sold
  $ 150,161     $ 139,560     $ 138,304  
 
                 
 
                       
Woods Cross Refinery
                       
Average refinery operating expenses per produced barrel sold
  $ 7.42     $ 4.86     $ 5.13  
Times sales of produced refined products sold (BPD)
    22,370       26,130       25,150  
Times number of days in period
    366       365       365  
 
                 
Refinery operating expenses for produced products sold
  $ 60,751     $ 46,352     $ 47,092  
 
                 
 
                       
Sum of refinery operating expenses per produced products sold from our two refineries (2)
  $ 210,912     $ 185,912     $ 185,396  
Add other refining segment operating expenses and rounding (1)
    21,599       23,357       23,015  
 
                 
Total refining segment operating expenses
    232,511       209,269       208,411  
Add HEP segment operating expenses
    35,218              
Add corporate and other costs
    (159 )     12       49  
 
                 
Operating expenses (exclusive of depreciation and amortization)
  $ 267,570     $ 209,281     $ 208,460  
 
                 
 
(1)   Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of Holly Asphalt Company.
 
(2)   The above calculations of refinery operating expenses per produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Average refinery operating expenses per produced barrel sold
  $ 5.14     $ 4.43     $ 4.83  
Times sales of produced refined products sold (BPD)
    111,950       115,050       105,090  
Times number of days in period
    366       365       365  
 
                 
Refinery operating expenses for produced products sold
  $ 210,912     $ 185,912     $ 185,396  
 
                 
Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Navajo Refinery
                       
Net operating margin per barrel
  $ 4.97     $ 11.28     $ 10.63  
Add average refinery operating expenses per produced barrel
    4.58       4.30       4.74  
 
                 
Refinery gross margin per barrel
    9.55       15.58       15.37  
Add average cost of products per produced barrel sold
    98.97       74.10       64.25  
 
                 
Average sales price per produced barrel sold
  $ 108.52     $ 89.68     $ 79.62  
Times sales of produced refined products sold (BPD)
    89,580       88,920       79,940  
Times number of days in period
    366       365       365  
 
                 
Refined product sales from produced products sold
  $ 3,557,967     $ 2,910,636     $ 2,323,160  
 
                 

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    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Woods Cross Refinery
                       
Net operating margin per barrel
  $ 9.18     $ 15.83     $ 11.97  
Add average refinery operating expenses per produced barrel
    7.42       4.86       5.13  
 
                 
Refinery gross margin per barrel
    16.60       20.69       17.10  
Add average cost of products per produced barrel sold
    93.47       69.40       64.99  
 
                 
Average sales price per produced barrel sold
  $ 110.07     $ 90.09     $ 82.09  
Times sales of produced refined products sold (BPD)
    22,370       26,130       25,150  
Times number of days in period
    366       365       365  
 
                 
Refined product sales from produced products sold
  $ 901,189     $ 859,229     $ 753,566  
 
                 
 
                       
Sum of refined product sales from produced products sold from our two refineries (4)
  $ 4,459,156     $ 3,769,865     $ 3,076,726  
Add refined product sales from purchased products and rounding (1)
    384,073       383,396       480,641  
 
                 
Total refined product sales
    4,843,229       4,153,261       3,557,367  
Add direct sales of excess crude oil(2)
    860,642       491,150       323,002  
Add other refining segment revenue (3)
    133,578       145,753       141,605  
 
                 
Total refining segment revenue
    5,837,449       4,790,164       4,021,974  
Add HEP segment sales and other revenues
    101,750              
Add corporate and other revenues
    2,641       1,578       1,752  
Subtract consolidations and eliminations
    (74,172 )           (509 )
 
                 
Sales and other revenues
  $ 5,867,668     $ 4,791,742     $ 4,023,217  
 
                 
 
(1)   We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments.
 
(2)   We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.
 
(3)   Other refining segment revenue includes the revenues associated with Holly Asphalt Company and revenue derived from feedstock and sulfur credit sales.
 
(4)   The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per barrel amounts)  
Net operating margin per barrel
  $ 5.82     $ 12.31     $ 10.95  
Add average refinery operating expenses per produced barrel
    5.14       4.43       4.83  
 
                 
Refinery gross margin per barrel
    10.96       16.74       15.78  
Add average cost of products per produced barrel sold
    97.87       73.03       64.43  
 
                 
Average sales price per produced barrel sold
  $ 108.83     $ 89.77     $ 80.21  
Times sales of produced refined products sold (BPD)
    111,950       115,050       105,090  
Times number of days in period
    366       365       365  
 
                 
Refined product sales from produced products sold
  $ 4,459,156     $ 3,769,865     $ 3,076,726  
 
                 

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Item 8. Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE COMPANY’S INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the Company’s internal control over financial reporting as of December 31, 2008 using the criteria for effective control over financial reporting established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that, as of December 31, 2008, the Company maintained effective internal control over financial reporting.
The Company’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. That report appears on page 62.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
and Stockholders of Holly Corporation
We have audited Holly Corporation’s (the “Company”) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Holly Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Holly Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Holly Corporation as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2008 and our report dated February 27, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 27, 2009

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Index to Consolidated Financial Statements
         
    Page
    Reference
    64  
 
       
    65  
 
       
    66  
 
       
    67  
 
       
    68  
 
       
    69  
 
       
    70  

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
and Stockholders of Holly Corporation
We have audited the accompanying consolidated balance sheets of Holly Corporation as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Corporation at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 27, 2009

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HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
                 
    December 31,     December 31,  
    2008     2007  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 40,805     $ 94,369  
Marketable securities
    49,194       158,233  
 
               
Accounts receivable: Product and transportation
    128,337       242,392  
Crude oil resales
    161,427       366,226  
Related party receivable
          6,151  
 
           
 
    289,764       614,769  
 
               
Inventories: Crude oil and refined products
    107,811       118,308  
Materials and supplies
    17,924       22,322  
 
           
 
    125,735       140,630  
 
               
Income taxes receivable
    6,350       16,356  
Prepayments and other
    18,775       10,264  
 
           
Total current assets
    530,623       1,034,621  
 
               
Properties, plants and equipment, at cost
    1,509,701       802,820  
Less accumulated depreciation
    (304,379 )     (271,970 )
 
           
 
    1,205,322       530,850  
 
               
Marketable securities (long-term)
    6,009       77,182  
 
               
Other assets: Turnaround costs
    34,309       8,705  
Goodwill
    27,542        
Intangibles and other
    70,420       12,587  
 
           
 
    132,271       21,292  
 
 
           
Total assets
  $ 1,874,225     $ 1,663,945  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 391,142     $ 782,976  
Accrued liabilities
    42,016       35,104  
Short-term debt — Holly Energy Partners
    29,000        
 
           
Total current liabilities
    462,158       818,080  
 
               
Long-term debt — Holly Energy Partners
    341,914        
Deferred income taxes
    69,491       38,933  
Other long-term liabilities
    64,330       36,712  
Commitments and contingencies
               
Distributions in excess of investment in Holly Energy Partners
          168,093  
Minority interest
    394,792       8,333  
 
               
Stockholders’ equity:
               
Preferred stock, $1.00 par value - 1,000,000 shares authorized; none issued
           
Common stock $.01 par value - 160,000,000 and 100,000,000 shares authorized; 73,543,873 and 73,269,219 shares issued as of December 31, 2008 and 2007, respectively
    735       733  
Additional capital
    121,298       109,125  
Retained earnings
    1,145,388       1,054,974  
Accumulated other comprehensive loss
    (35,081 )     (19,076 )
Common stock held in treasury, at cost - 23,600,653 and 20,653,050 shares as of December 31, 2008 and 2007, respectively
    (690,800 )     (551,962 )
 
           
Total stockholders’ equity
    541,540       593,794  
 
 
           
Total liabilities and stockholders’ equity
  $ 1,874,225     $ 1,663,945  
 
           
See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
                         
    Years Ended December 31,  
    2008     2007     2006  
Sales and other revenues
  $ 5,867,668     $ 4,791,742     $ 4,023,217  
 
                       
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)
    5,280,699       4,003,488       3,349,404  
Operating expenses (exclusive of depreciation and amortization)
    267,570       209,281       208,460  
General and administrative expenses (exclusive of depreciation and amortization)
    54,906       68,773       63,255  
Depreciation and amortization
    63,789       43,456       39,721  
Exploration expenses, including dry holes
    372       412       486  
 
                 
Total operating costs and expenses
    5,667,336       4,325,410       3,661,326  
 
                 
 
                       
Income from operations
    200,332       466,332       361,891  
 
                       
Other income (expense):
                       
Equity in earnings of Holly Energy Partners
    2,990       19,109       12,929  
Minority interests in earnings of Holly Energy Partners
    (7,041 )            
Impairment of equity securities
    (3,724 )            
Gain on sale of HPI
    5,958              
Interest income
    10,824       15,089       9,757  
Interest expense
    (23,955 )     (1,086 )     (1,076 )
 
                 
 
    (14,948 )     33,112       21,610  
 
                 
Income from continuing operations before income taxes
    185,384       499,444       383,501  
 
                       
Income tax provision:
                       
Current
    31,892       142,245       126,181  
Deferred
    32,934       23,071       10,422  
 
                 
 
    64,826       165,316       136,603  
 
                 
Income from continuing operations
    120,558       334,128       246,898  
 
                       
Discontinued operations
                       
Income from discontinued operations
                5,660  
Gain on sale of discontinued operations
                14,008  
 
                 
Income from discontinued operations, net of taxes
                19,668  
 
                 
 
                       
Net income
  $ 120,558     $ 334,128     $ 266,566  
 
                 
 
                       
Basic earnings per share:
                       
Continuing operations
  $ 2.40     $ 6.09     $ 4.33  
Discontinued operations
                0.35  
 
                 
Net income
  $ 2.40     $ 6.09     $ 4.68  
 
                 
 
                       
Diluted earnings per share:
                       
Continuing operations
  $ 2.38     $ 5.98     $ 4.24  
Discontinued operations
                0.34  
 
                 
Net income
  $ 2.38     $ 5.98     $ 4.58  
 
                 
 
                       
Average number of common shares outstanding:
                       
Basic
    50,202       54,852       56,976  
Diluted
    50,549       55,850       58,210  
See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                         
    Years Ended December 31,  
    2008     2007     2006  
Cash flows from operating activities:
                       
Net income
  $ 120,558     $ 334,128     $ 266,566  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization (includes discontinued operations in 2006)
    63,789       43,456       40,270  
Deferred income taxes (includes discontinued operations in 2006)
    32,934       23,071       7,980  
Minority interest in earnings of Holly Energy Partners
    7,041              
Distributions in excess of equity in earnings of Holly Energy Partners and joint ventures
    3,067       3,688       7,379  
Equity based compensation expense
    7,467       9,993       5,507  
Gain on sale of assets, before income taxes
    (5,958 )           (22,328 )
Change in fair value — interest rate swaps
    2,282              
Impairment of equity securities
    3,724              
(Increase) decrease in current assets:
                       
Accounts receivable
    331,978       (216,295 )     12,059  
Inventories
    15,006       (10,955 )     (33,792 )
Income taxes receivable
    10,006       (7,301 )     (9,055 )
Prepayments and other
    (398 )     1,817       5,890  
Increase (decrease) in current liabilities:
                       
Accounts payable
    (393,186 )     264,217       (26,370 )
Accrued liabilities
    (2,149 )     (16,476 )     15,665  
Income taxes payable
    1,781             (5,323 )
Turnaround expenditures
    (34,751 )     (2,669 )     (7,672 )
Other, net
    (7,701 )     (3,937 )     (11,593 )
 
                 
Net cash provided by operating activities
    155,490       422,737       245,183  
 
                       
Cash flows from investing activities:
                       
Additions to properties, plants and equipment — Holly Corporation
    (383,742 )     (161,258 )     (120,429 )
Additions to properties, plants and equipment — Holly Energy Partners
    (34,317 )            
Proceeds from sale of crude pipelines and tankage assets
    171,000              
Proceeds from sale of HPI
    5,958              
Net proceeds from sale of Montana Refinery
                48,872  
Increase in cash due to consolidation of Holly Energy Partners
    7,295              
Purchases of marketable securities
    (769,142 )     (641,144 )     (211,972 )
Sales and maturities of marketable securities
    945,461       509,345       319,334  
Investment in Holly Energy Partners
    (290 )            
 
                 
Net cash provided by (used for) investing activities
    (57,777 )     (293,057 )     35,805  
 
                       
Cash flows from financing activities:
                       
Net borrowings under credit agreement — Holly Energy Partners
    29,000              
Deferred financing costs
    (913 )            
Purchase of treasury stock
    (151,106 )     (207,196 )     (175,394 )
Contribution from joint venture partner
    17,000       8,333        
Dividends
    (29,064 )     (23,208 )     (15,002 )
Distributions to minority interests
    (22,098 )            
Issuance of common stock upon exercise of options
    1,005       2,288       2,645  
Excess tax benefit from equity based compensation
    5,694       30,355       11,816  
Purchase of units for restricted grants — Holly Energy Partners
    (795 )            
 
                 
Net cash used for financing activities
    (151,277 )     (189,428 )     (175,935 )
 
                       
Cash and cash equivalents:
                       
 
                       
Increase (decrease) for the period
    (53,564 )     (59,748 )     105,053  
Beginning of period
    94,369       154,117       49,064  
 
                 
End of period
  $ 40,805     $ 94,369     $ 154,117  
 
                 
See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
                                                 
                            Accumulated                
                            Other             Total  
    Common     Additional     Retained     Comprehensive     Treasury     Stockholders’  
    Stock     Capital     Earnings     Income (Loss)     Stock     Equity  
Balance at December 31, 2005
  $ 354     $ 43,344     $ 495,819     $ (4,802 )   $ (157,364 )   $ 377,351  
Net income
                266,566                   266,566  
Dividends
                (16,391 )                 (16,391 )
Other comprehensive income
                      2,831             2,831  
Issuance of common stock upon exercise of stock options
    6       2,638                         2,644  
Tax benefit from stock options
          12,031                         12,031  
Amortization of stock options
          139                         139  
Issuance of restricted stock, net of forfeitures
          5,369                         5,369  
Other equity based compensation
          3,337                         3,337  
Purchase of treasury stock
                            (178,396 )     (178,396 )
Two-for-one stock split
    358       (358 )                        
Adjustment to initially apply SFAS No. 158, net of tax
                      (9,387 )           (9,387 )
 
                                   
 
                                               
Balance at December 31, 2006
  $ 718     $ 66,500     $ 745,994     $ (11,358 )   $ (335,760 )   $ 466,094  
Net income
                334,128                   334,128  
Dividends
                (25,148 )                 (25,148 )
Other comprehensive loss
                      (7,718 )           (7,718 )
Issuance of common stock upon exercise of stock options
    11       2,277                         2,288  
Tax benefit from stock options
          26,017                         26,017  
Issuance of restricted stock, net of forfeitures
    4       9,993                         9,997  
Other equity based compensation
          4,338                         4,338  
Purchase of treasury stock
                            (216,202 )     (216,202 )
 
                                   
 
                                               
Balance at December 31, 2007
  $ 733     $ 109,125     $ 1,054,974     $ (19,076 )   $ (551,962 )   $ 593,794  
Net income
                120,558                   120,558  
Dividends
                (30,144 )                 (30,144 )
Other comprehensive loss
                      (16,005 )           (16,005 )
Issuance of common stock upon exercise of stock options
    2       1,003                         1,005  
Tax benefit from stock options
          3,364                         3,364  
Issuance of restricted stock, net of forfeitures
          5,476                         5,476  
Other equity based compensation
          2,330                         2,330  
Purchase of treasury stock
                            (138,838 )     (138,838 )
 
                                   
 
                                               
Balance at December 31, 2008
  $ 735     $ 121,298     $ 1,145,388     $ (35,081 )   $ (690,800 )   $ 541,540  
 
                                   
See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
                         
    Years Ended December 31,  
    2008     2007     2006  
Net income
  $ 120,558     $ 334,128     $ 266,566  
 
                       
Other comprehensive income (loss):
                       
 
                       
Securities available-for-sale:
                       
Unrealized gain (loss) on available-for-sale securities
    1,146       1,857       (777 )
Reclassification adjustment to net income on sale of securities
    (1,315 )     (78 )     (131 )
 
                 
Total unrealized gain (loss) on available-for-sale securities
    (169 )     1,779       (908 )
 
                       
Retirement medical obligation adjustment
    1,433       (5,038 )      
Minimum pension liability adjustment
    (21,572 )     (9,373 )     5,542  
 
                       
Other comprehensive loss of Holly Energy Partners:
                       
Change in fair value of cash flow hedge
    (12,967 )            
Less minority interest in other comprehensive loss
    7,079              
 
                 
Other comprehensive loss of Holly Energy Partners, net of minority interest
    (5,888 )            
 
                 
 
                       
Other comprehensive income (loss) before income taxes
    (26,196 )     (12,632 )     4,634  
 
                       
Income tax expense (benefit)
    (10,191 )     (4,914 )     1,803  
 
                 
 
                       
Other comprehensive income (loss)
    (16,005 )     (7,718 )     2,831  
 
                 
 
                       
Total comprehensive income
  $ 104,553     $ 326,410     $ 269,397  
 
                 
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: References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.
We are principally an independent petroleum refiner that produces high value light products such as gasoline, diesel fuel and jet fuel. Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns a petroleum refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery can process sour (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. Our refinery located just north of Salt Lake City, Utah (the “Woods Cross Refinery”) is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes regional sweet (lower sulfur) and sour Canadian crude oils.
At December 31, 2008, we owned a 46% interest in Holly Energy Partners, L.P. (“HEP”) which includes our 2% general partner interest. HEP has logistic assets including petroleum product and crude oil pipelines located in Texas, New Mexico, Oklahoma and Utah; ten refined product terminals; a jet fuel terminal; two refinery truck rack facilities, a refined products tank farm facility, on-site crude oil tankage at both our Navajo and Woods Cross Refineries and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).
On February 29, 2008, HEP acquired certain crude pipelines and tankage assets from us (the “Crude Pipelines and Tankage Assets”) that service our Navajo and Woods Cross Refineries (see Note 3).
We sold substantially all of the oil and gas properties of Holly Petroleum, Inc. (“HPI”), a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6.0 million, resulting in a gain of $6.0 million.
On March 31, 2006, we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). Accordingly, the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale are shown in discontinued operations (see Note 2).
Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we control through 50% or more ownership or through 50% or more variable interest in entities that are considered variable interest entities. All significant intercompany transactions and balances have been eliminated.
Use of Estimates: The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Cash Equivalents: We consider all highly liquid instruments with a maturity of three months or less at the date of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are primarily invested in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings.

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Marketable Securities: We consider all marketable debt securities with maturities greater than three months at the date of purchase to be marketable securities. Our marketable securities are primarily issued by government entities with the maximum maturity of any individual issue not more than two years, while the maximum duration of the portfolio of investments is not greater than one year. These instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income.
Fair Value Measurements: We adopted Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements” on January 1, 2008 for financial instruments that we recognize at fair value on a recurring basis.
This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels. Under this hierarchy, quoted prices in active markets for identical assets or liabilities are considered the most reliable evidence of fair value and are given the highest priority level (level 1). Quoted market prices for similar assets and liabilities in an active market, quoted prices for identical assets or liabilities in an inactive market and calculation techniques utilizing observable market inputs are given a lower priority level (level 2). Unobservable inputs are considered the least reliable and are given the lowest priority level (level 3).
We have investments in marketable debt and equity securities that are measured at fair value on a recurring basis using level 1 inputs. Fair value measurements are based on quoted prices in active markets. See Note 6 for additional information on these instruments.
HEP has interest rate swaps that are measured at fair value on a recurring basis using level 2 inputs. Interest rate swap fair value measurements are based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreements. Fair value measurements are computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input, at the respective measurement dates. See Note 11 for additional information on the interest rate swaps.
Accounts Receivable: The majority of the accounts receivable are due from companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, is required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal. Accounts receivable attributable to crude oil resales generally represent the sell side of excess crude oil sales to other purchasers and / or users in cases when our crude oil supplies are in excess of our immediate needs as well as certain reciprocal buy /sell exchanges of crude oil. At times we enter into such buy / sell exchanges to facilitate the delivery of quantities to certain locations. In many cases, we enter into net settlement agreements relating to the buy/sell arrangements, which may mitigate credit risk.
Inventories: Inventories are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.
Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. No impairments of long-lived assets were recorded during the years ended December 31, 2008, 2007 and 2006.

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Asset Retirement Obligations: We record legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.
We have asset retirement obligations with respect to certain assets due to legal obligations to clean and/or dispose of various component parts at the time they are retired. At December 31, 2008, we have an asset retirement obligation of $1.3 million, which is included in “Other long-term liabilities” in our consolidated balance sheets.
Intangibles and Goodwill: Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired.
We reconsolidated HEP on March 1, 2008 and as a result, recorded $27.5 million in goodwill. Additionally, our consolidated HEP assets include a third-party transportation agreement having an expected remaining term through 2035. The transportation agreement is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $1.9 million. At December 31, 2008, the balance of this transportation agreement was $52.5 million, net of accumulated amortization of $1.5 million, which is included in “Intangible and Others” in our consolidated balance sheets. Amortization expense for the year ended December 31, 2008 was $1.5 million, representing amortization from March 1, 2008 (date of reconsolidation) through December 31, 2008.
No impairments of intangibles or goodwill were recorded during the years ended December 31, 2008, 2007 and 2006.
Variable Interest Entity: HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standard Board (“FASB”) Interpretation (“FIN”) No. 46(R). A VIE is defined as a legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest.
Under the provisions of FIN No. 46(R), HEP’s purchase of certain pipelines and tankage assets from us (see Note 3) qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we reevaluated whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting. As a result, our financial statements include the consolidated results of HEP. Amounts allocated to HEP’s minority interest holders are recorded to minority interest.
Under the equity method of accounting, prior to March 1, 2008, we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance.
Investments in Joint Ventures: We consolidate the results of our joint ventures where we have an ownership interest of greater than 50% and use the equity method of accounting for investments in which we a 50% or less ownership interest. As of December 31, 2008 we have no investments in joint ventures that we account for using the equity method of accounting.
Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in the balance sheet and measured at fair value. Changes in the derivative instrument’s fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 11, Debt for additional information on HEP’s interest rate swap and hedging activities.

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Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. Pipeline transportation revenues are recognized as products are shipped on our pipelines. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling costs incurred are reported in cost of products sold.
Depreciation: Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 12 to 25 years for refining facilities, 10 to 25 years for pipeline and terminal facilities, 3 to 5 years for transportation vehicles, 10 to 40 years for buildings and improvements and 7 to 30 years for other fixed assets.
Cost Classifications: Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs.
Deferred Maintenance Costs: Our refinery units require regular major maintenance and repairs which are commonly referred to as “turnarounds”. Catalysts used in certain refinery processes also require regular “change-outs”. The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred.
Environmental Costs: Environmental costs are charged to operating expenses 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, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.
Contingencies: We are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters.
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.
Potential interest and penalties related to income tax matters are recognized in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.
New Accounting Pronouncements:
SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51”
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent

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company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. This standard is effective as of January 1, 2009. As a result, our minority interest balance will be reclassified as a component of “Stockholders’ equity” in our consolidated balance sheets. At December 31, 2008, our minority interest balance was $394.8 million.
SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133” In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008 and interim periods with in those fiscal years. This standard is effective as of January 1, 2009 and will not have a material impact on our financial condition, results of operations and cash flows.
NOTE 2: Discontinued Operations
On March 31, 2006 we sold the Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. In accounting for the sale, we recorded a pre-tax gain of $22.3 million. The Montana Refinery assets disposed of had a net book value at March 31, 2006 of $13.7 million for property, plant and equipment, $15.4 million for inventories and $2.1 million for other assets, with current liabilities assumed amounting to $0.3 million.
The following tables provide summarized income statement information related to discontinued operations:
         
    Year Ended  
    December  
    31, 2006  
    (In thousands)  
Sales and other revenues from discontinued operations
  $ 53,913  
 
     
 
       
Income from discontinued operations before income taxes
  $ 9,021  
Income tax expense
    (3,361 )
 
     
Income from discontinued operations, net
    5,660  
 
       
Gain on sale of discontinued operations before income taxes
    22,328  
Income tax expense
    (8,320 )
 
     
Gain on sale of discontinued operations, net
    14,008  
 
     
 
       
Income from discontinued operations, net
  $ 19,668  
 
     
In accordance with the Montana Refinery sale agreement, we retained certain financial liabilities, including certain environmental liabilities related to required remediation and corrective action for environmental conditions that existed at the time of sale and for financial penalties for infractions that occurred prior to the sale. As of December 31, 2008, we had an accrual of $1.8 million related to such environmental liabilities which is included in our environmental liability accrual as discussed in Note 10.
NOTE 3: Holly Energy Partners
HEP is a publicly held master limited partnership that commenced operations July 13, 2004 upon the completion of its initial public offering. We currently have a 46% ownership interest in HEP, including our 2% general partner interest.

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HEP is a variable interest entity as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s acquisition of the Crude Pipelines and Tankage Assets (discussed below) qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.
On February 29, 2008, we closed on the sale of the Crude Pipelines and Tankage Assets to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.
In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with HEP (the “HEP CPTA”). Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the producer price index (“PPI”), but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a FERC adjustment factor. Additionally, we amended our omnibus agreement with HEP (the “Omnibus Agreement”) to provide $7.5 million of indemnification for a period of up to 15-years for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP.
HEP also serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (“HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on their refined product pipelines and / or throughput in their terminals volumes of refined products that will result in minimum annual payments to HEP. Under the HEP IPA, we agreed to transport minimum volumes of intermediate products on the intermediate pipelines that will result in minimum annual payments to HEP. Minimum payments for both agreements are adjusted annually on July 1 based on increases in the PPI. Following the July 1, 2008 PPI rate adjustment, minimum payments under the HEP PTA and the HEP IPA are $41.2 million and $13.3 million, respectively, for the twelve months ending June 30, 2009.
The following table sets forth the changes in our investment account in HEP for the period from January 1, 2008 through February 29, 2008, prior to our reconsolidation effective March 1, 2008:
         
    (In thousands)  
Investment in HEP balance at December 31, 2007
  $ (168,093 )
Equity in the earnings of HEP
    2,990  
Regular quarterly distributions from HEP
    (6,057 )
Consideration received in excess of basis in Crude Pipeline and Tankage Assets
    (153,223 )
HEP common units received
    9,000  
Purchase of additional HEP common units
    104  
Contribution made to maintain 2% general partner interest
    186  
 
     
Investment in HEP balance at February 29, 2008
  $ (315,093 )
 
     
The balance sheet impact of our reconsolidation of HEP on March 1, 2008 was an increase in cash of $7.3 million, an increase in other current assets of $5.9 million, an increase in property, plant and equipment of $336.9 million, an increase in goodwill, intangibles and other assets of $81.5 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $338.5 million, a decrease in other long-term liabilities of $0.5 million, an increase in minority interest of $389.1 million and a decrease in distributions in excess of investment in HEP of $315.1 million.
We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under the HEP PTA, HEP IPA, HEP CPTA and the Omnibus Agreement. Effective March 1, 2008, we reconsolidated HEP. As a result, our financial statements include the consolidated results of

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HEP and intercompany transactions with HEP are eliminated. Related party transactions prior to our reconsolidation of HEP are as follows:
    Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008 and $61.0 million for the year ended December 31, 2007, respectively.
 
    We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 and $2.0 million for the year ended December 31, 2007, respectively, for general and administrative services under the Omnibus Agreement which we recorded as a reduction in expenses.
 
    HEP reimbursed us for costs of employees supporting their operations of $2.1 million for the period from January 1, 2008 through February 29, 2008 and $8.5 million for the year ended December 31 2007, respectively, which we recorded as a reduction in expenses.
 
    We reimbursed HEP $0.3 million for the year ended December 31, 2007 for certain costs paid on our behalf.
 
    We received as regular distributions on our subordinated units, common units and general partner interest $6.1 million for the period from January 1, 2008 through February 29, 2008 and $22.8 million for the year ended December 31, 2007, respectively. Our distributions included $0.7 million for the period from January 1, 2008 through February 29, 2008 and $2.2 million for the year ending December 31, 2007, respectively, in incentive distributions with respect to our general partner interest.
 
    We had a related party receivable from HEP of $6.0 million at February 29, 2008 and December 31, 2007.
 
    We had accounts payable to HEP of zero and $5.7 million at February 29, 2008 and December 31, 2007, respectively.
NOTE 4: Earnings Per Share
Basic earnings per share from continuing operations is calculated as income from continuing operations divided by the average number of shares of common stock outstanding. Diluted earnings per share from continuing operations assumes, when dilutive, the issuance of the net incremental shares from stock options and variable performance shares. The following is a reconciliation of the denominators of the basic and diluted per share computations for income from continuing operations:
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands, except per share data)  
Income from continuing operations
  $ 120,558     $ 334,128     $ 246,898  
 
                       
Average number of shares of common stock outstanding
    50,202       54,852       56,976  
Effect of dilutive stock options, variable restricted shares and performance share units
    347       998       1,234  
 
                 
Average number of shares of common stock outstanding assuming dilution
    50,549       55,850       58,210  
 
                 
 
                       
Basic earnings per share from continuing operations
  $ 2.40     $ 6.09     $ 4.33  
 
                       
Diluted earnings per share from continuing operations
  $ 2.38     $ 5.98     $ 4.24  
NOTE 5: Stock-Based Compensation
On December 31, 2008, Holly had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for these plans was $7.6 million, $10.8 million and $21.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $2.9 million, $4.2 million and $7.6 million for the years ended December 31, 2008, 2007 and 2006, respectively. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods. At December 31, 2008, 2,407,172 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which reservation allows for awards of options, restricted stock, or other performance awards.

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Additionally in 2008, we recorded $1.7 million of equity based compensation expense attributable to HEP’s equity based compensation plan as a result of our reconsolidation effective March 1, 2008.
Stock Options
Under our long-term incentive compensation plan and a previous stock option plan, we have granted stock options to certain officers and other key employees. All the options have been granted at prices equal to the market value of the shares at the time of the grant and normally expire on the tenth anniversary of the grant date. These awards generally vest 20% at the end of each of the five years after the grant date. There have been no options granted since December 2001. The fair value on the date of grant for each option awarded was been estimated using the Black-Scholes option pricing model.
A summary of option activity and changes during the year ended December 31, 2008 is presented below:
                                 
                    Weighted-        
            Weighted-     Average     Aggregate  
            Average     Remaining     Intrinsic  
            Exercise     Contractual     Value  
Options   Shares     Price     Term     ($000)  
Outstanding at January 1, 2008
    491,200     $ 2.56                  
Exercised
    (406,000 )   $ 2.47                  
 
                             
Outstanding at December 31, 2008
    85,200     $ 2.98       2.2     $ 1,300  
 
                       
Exercisable at December 31, 2008
    85,200     $ 2.98       2.2     $ 1,300  
 
                       
The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006, was $8.6 million, $68.0 million and $30.9 million, respectively.
All outstanding stock options granted became fully vested during 2006. The total fair value of options vested during the year ended December 31, 2006 was $0.4 million.
Cash received from option exercises under the stock option plans for the years ended December 31, 2008, 2007 and 2006, was $1.0 million, $2.3 million and $2.6 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $3.4 million, $26.0 million and $12.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Restricted Stock
Under our long-term incentive compensation plan, we grant certain officers, other key employees and outside directors restricted stock awards with substantially all awards vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain earnings per share targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, was measured based on the market price as of the date of grant and is being amortized over the respective vesting period.
A summary of restricted stock activity and changes during the year ended December 31, 2008 is presented below:
                         
            Weighted-        
            Average        
            Grant-Date     Aggregate Intrinsic  
Restricted Stock   Grants     Fair Value     Value ($000)  
Outstanding at January 1, 2008 (non-vested)
    298,565     $ 27.22          
Vesting and transfer of ownership to recipients
    (138,648 )   $ 23.58          
Granted
    86,409     $ 45.91          
Forfeited
    (11,016 )   $ 34.87          
 
                     
Outstanding at December 31, 2008 (non-vested)
    235,310     $ 35.86     $ 4,290  
 
                 

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The total fair value of restricted stock vested and transferred to recipients during the years ended December 31, 2008, 2007 and 2006 was $2.5 million, $12.9 million and $5.5 million, respectively. As of December 31, 2008, there was $2.0 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.2 years.
Performance Share Units
Under our long-term incentive compensation plan, we grant certain officers and other key employees performance share units, which are payable in either cash or stock upon meeting certain criteria over the service period, and generally vest over a period of one to three years. Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or a “market performance” criteria.
During the year ended December 31, 2008, we granted 60,605 performance share units with a fair value based on our grant date closing stock price of $47.47. All shares were granted during the first quarter of 2008 and are payable in stock and are subject to certain financial performance criteria.
The fair value of each performance share unit award subject to the financial performance criteria and payable in stock is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of December 31, 2008, estimated share payouts for outstanding non-vested performance share unit awards ranged from 80% to 156%.
The fair value of each performance share unit award based on market performance criteria and payable in stock is computed based on an expected-cash-flow approach. The analysis utilizes the grant date closing stock price, dividend yield, historical total returns, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns and comparison of expected total returns with the peer group. The expected total return and historical standard deviation are applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns.
A summary of performance share unit activity and changes during the year ended December 31, 2008 is presented below:
                                 
                    Financial        
    Market Performance     Performance        
    Payable in     Stock     Stock     Total  
    Cash     Settled     Settled     Performance  
Performance Share Units   Grants     Grants     Grants     Share Units  
Outstanding at January 1, 2008 (non-vested)
    81,450       42,474       116,156       240,080  
Vesting and payment of benefit to recipients
    (81,450 )     (42,474 )           (123,924 )
Granted
                60,605       60,605  
Forfeited
                (7,092 )     (7,092 )
 
                       
Outstanding at December 31, 2008 (non-vested)
                169,669       169,669  
 
                       
For the year ended December 31, 2008 we paid $6.0 million and issued 84,948 shares of our common stock (representing a 200% share payout) having a fair value of $2.7 million related to vested performance share units. Based on the weighted average grant date fair value of $42.50 there was $5.2 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.3 years.
NOTE 6: Cash and Cash Equivalents and Investments in Marketable Securities
Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities. In addition, we have 1,000,000 shares of Connacher common stock that was received as partial consideration upon our sale of the Montana Refinery in 2006.

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We invest in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. VRDN may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments including investments in equity securities are classified as available-for-sale, and as a result, are reported at fair value. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are considered temporary and are reported as a component of accumulated other comprehensive income. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.
During the year ended December 31, 2008, we recorded an impairment loss of $3.7 million related to our investment in Connacher common stock having an initial cost basis of $4.3 million. Although this investment in equity securities was in an unrealized loss position for less than 12-months, we accounted for this as an other-than-temporary decline due to the severity of the loss in fair value of this investment.
The following is a summary of our available-for-sale securities at December 31, 2008:
                                 
    Available-for-Sale Securities  
                            Estimated  
            Gross     Recognized     Fair Value  
    Amortized     Unrealized     Impairment     (Net Carrying  
    Cost     Gain     Loss     Amount)  
    (In thousands)  
States and political subdivisions
  $ 54,389     $ 210     $     $ 54,599  
Equity securities
    4,328             (3,724 )     604  
 
                       
Total marketable securities
  $ 58,717     $ 210     $ (3,724 )   $ 55,203  
 
                       
For the year ended December 31, 2008, we received a total of $945.5 million related to sales and maturities of marketable debt securities.
The following is a summary of our available-for-sale securities at December 31, 2007:
                         
    Available-for-Sale Securities  
                    Estimated  
            Gross     Fair Value  
    Amortized     Unrealized     (Net Carrying  
    Cost     Gain (Loss)     Amount)  
    (In thousands)  
States and political subdivisions
  $ 230,709     $ 866     $ 231,575  
Equity securities
    4,328       (488 )     3,840  
 
                 
Total marketable securities
  $ 235,037     $ 378     $ 235,415  
 
                 
For the year ended December 31, 2007, we received a total of $509.3 million related to sales and maturities of marketable debt securities.
NOTE 7: Inventories
Inventories are stated at the lower of cost, using the LIFO method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs.

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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.
Inventory consists of the following components:
                 
    December 31,  
    2008     2007  
    (In thousands)  
Crude oil
  $ 21,446     $ 25,364  
Other raw materials and unfinished products (1)
    2,640       7,226  
Finished products (2)
    83,725       85,718  
Process chemicals (3)
    3,800       4,312  
Repairs and maintenance supplies and other
    14,124       18,010  
 
           
Total inventory
  $ 125,735     $ 140,630  
 
           
 
(1)   Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.
 
(2)   Finished products include gasolines, jet fuels, diesels, asphalts, LPG’s and residual fuels.
 
(3)   Process chemicals include catalysts, additives and other chemicals.
The excess of current cost over the LIFO value of inventory was $33.0 million and $199.4 million at December 31, 2008 and 2007, respectively. We recognized a reduction in cost of products sold of $8.4 million for the year ended December 31, 2008 and recognized a charge of $0.8 million to cost of products sold for the year ended December 31, 2007. The 2008 cost reduction resulted from liquidations of certain LIFO inventory quantities that were carried at lower costs as compared to acquisition costs at the beginning of the year. The $0.8 million charge for 2007 was the result of certain LIFO inventory liquidations that were carried at higher costs as compared to acquisition costs at the beginning of the year.
NOTE 8: Properties, Plants and Equipment
                 
    December 31,  
    2008     2007  
    (In thousands)  
Land, buildings and improvements
  $ 54,529     $ 24,340  
Refining facilities
    493,706       478,445  
Pipelines and terminals
    338,558       68,709  
Transportation vehicles
    19,313       13,564  
Oil and gas exploration and development
          2,917  
Other fixed assets
    50,187       43,534  
Construction in progress
    553,408       171,311  
 
           
 
    1,509,701       802,820  
Accumulated depreciation
    (304,379 )     (271,970 )
 
           
 
  $ 1,205,322     $ 530,850  
 
           
During the year ended December 31, 2008, $1.0 million in interest attributable to HEP’s construction projects was capitalized. We did not capitalize any interest in 2007.
Depreciation expense was $53.3 million, $35.8 million and $30.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. Depreciation expense for the year ended December 31, 2008 includes $17.5 million of depreciation expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.

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NOTE 9: Joint Venture
In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the “UNEV Pipeline”). Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The total cost of the pipeline project including terminals is expected to be $300.0 million. Our share of this cost would be $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff rate. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.
The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.
NOTE 10: Environmental Costs
Consistent with our accounting policy for environmental remediation costs, we expensed $0.4 million, $2.3 million and $5.6 million for the years ended December 31, 2008, 2007 and 2006, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheet was $7.3 million and $8.6 million at December 31, 2008 and 2007, respectively, of which $4.2 million and $5.3 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are expected to be incurred over the next several years and are not discounted to their present value.
NOTE 11: Debt
Credit Facilities
In March 2008, we entered into an amended and restated $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America as administrative agent and lender. The Credit Agreement has a term of five years and an option to increase the facility to $300.0 million subject to certain conditions. This credit facility expires in 2013 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2008. At December 31, 2008, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.5 million at December 31, 2008.
HEP has a $300.0 million senior secured revolving credit agreement (the “HEP Credit Agreement”) with Union Bank of California, N.A. as one of the lenders and as administrative agent and an option to increase the facility to $370.0 million subject to certain conditions. The HEP Credit Facility expires in August 2011 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general partnership purposes. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included in our Consolidated Balance Sheets at December 31, 2008 consist of $5.3 million in cash and cash equivalents, $5.1 million in trade accounts receivable and other current assets, $354.1 million in property, plant and equipment, net and $56.1 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement.

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HEP Senior Notes Due 2015
The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service on up to $35.0 million of the principal amount of the HEP Senior Notes.
At December 31, 2008, the carrying amount of HEP’s long-term debt was as follows:
         
    (In thousands)  
HEP Credit Agreement
  $ 200,000  
HEP Senior Notes
       
Principal
    185,000  
Unamortized discount
    (16,223 )
Unamortized premium — de-designated fair value hedge
    2,137  
 
     
 
    170,914  
 
     
 
       
Total debt
    370,914  
Less short-term borrowings under HEP Credit Agreement
    29,000  
 
     
 
       
Total long-term debt
  $ 341,914  
 
     
Interest Rate Risk Management
As of December 31, 2008, HEP had three interest rate swap contracts.
HEP entered into an interest rate swap to hedge their exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that HEP used to finance their purchase of the Crude Pipelines and Tankage Assets from us. This interest rate swap effectively converts their $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2008. The maturity date of this swap contract is February 28, 2013. HEP intends to renew the HEP Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.
HEP designated this interest rate swap as a cash flow hedge. Based on their assessment of effectiveness using the change in variable cash flows method, HEP determined that this interest rate swap is effective in offsetting the variability in interest payments on the $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, HEP adjusts their cash flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, HEP measures hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of the swap against the expected future interest payments on the $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008, HEP had no ineffectiveness on their cash flow hedge.
HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36% as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.
In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of their hedged

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long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.
HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with a corresponding entry to interest expense. For the year ended December 31, 2008, HEP recognized $2.3 million in interest expense attributable to fair value adjustments to its interest rate swaps.
Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the HEP Senior Notes. This hedge met the requirements to assume no ineffectiveness and was accounted for using the “shortcut” method of accounting whereby offsetting fair value adjustments to the underlying swap were made to the carrying value of the HEP Senior Notes, effectively adjusting the carrying value of this $60.0 million to its fair value. HEP de-designated this hedge in October 2008. At this time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.
HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.
Additional information on HEP’s interest rate swaps is as follows:
                                 
    Balance Sheet             Location of Offsetting     Offsetting  
Interest Rate Swaps   Location     Fair Value     Balance     Amount  
                    (In thousands)          
Asset
                               
Fixed-to-variable interest rate swap - $60 million of 6.25% Senior Notes
                  Long-term debt   $ (2,195 )
 
  Other assets   $ 4,079     Interest expense     (1,884 )
 
                           
 
 
          $ 4,079             $ (4,079 )
 
                           
 
                               
Liability
                               
Cash flow hedge - $171 million LIBOR based debt
  Other long-term liabilities   $ (12,967 )   Accumulated other comprehensive income   $ 12,967  
Variable-to-fixed interest rate swap — $60 million
  Other long-term liabilities     (4,166 )   Interest expense     4,166  
 
                           
 
          $ (17,133 )           $ 17,133  
 
                           
We made cash interest payments of $14.3 million, $0.8 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.
NOTE 12: Income Taxes
The provision for income taxes from continuing operations is comprised of the following:
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
Current
                       
Federal
  $ 27,795     $ 113,999     $ 105,469  
State
    4,097       28,246       20,712  
Deferred
                       
Federal
    27,727       21,867       9,490  
State
    5,207       1,204       932  
 
                 
 
  $ 64,826     $ 165,316     $ 136,603  
 
                 

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The statutory federal income tax rate applied to pre-tax book income from continuing operations reconciles to income tax expense as follows:
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
Tax computed at statutory rate
  $ 64,884     $ 174,805     $ 134,225  
State income taxes, net of federal tax benefit
    7,230       19,478       14,957  
Federal tax credits
    (1,896 )     (16,078 )     (10,776 )
Domestic production activities deduction
    (2,380 )     (8,670 )      
Tax exempt interest
    (2,772 )     (4,200 )      
Other
    (240 )     (19 )     (1,803 )
 
                 
 
  $ 64,826     $ 165,316     $ 136,603  
 
                 
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 amounts used for income tax purposes. Our deferred income tax assets and liabilities for continuing operations as of December 31, 2008 and 2007 are as follows:
                         
    December 31, 2008  
    Assets     Liabilities     Total  
    (In thousands)  
Deferred taxes
                       
Accrued employee benefits
  $ 7,135     $ (29 )   $ 7,106  
Accrued postretirement benefits
    2,607       286       2,893  
Accrued environmental costs
    1,202             1,202  
Inventory differences
    247       489       736  
Prepayments and other
    1,066       (2,297 )     (1,231 )
 
                 
Total current(1)
    12,257       (1,551 )     10,706  
Properties, plants and equipment (due primarily to tax in excess of book depreciation)
          (122,684 )     (122,684 )
Accrued postretirement benefits
    14,824             14,824  
Accrued environmental costs
    1,591             1,591  
Deferred turnaround costs
          (11,491 )     (11,491 )
Investments in HEP
    44,557       55       44,612  
Other
    6,212       (2,555 )     3,657  
 
                 
Total noncurrent
    67,184       (136,675 )     (69,491 )
 
                 
Total
  $ 79,441     $ (138,226 )   $ (58,785 )
 
                 
                         
    December 31, 2007  
    Assets     Liabilities     Total  
    (In thousands)  
Deferred taxes Accrued employee benefits
  $ 9,703     $ (29 )   $ 9,674  
Accrued postretirement benefits
    1,913             1,913  
Accrued environmental costs
    1,282             1,282  
Inventory differences
    247       (6,644 )     (6,397 )
Prepayments and other
    2,901       (6,480 )     (3,579 )
 
                 
Total current(1)
    16,046       (13,153 )     2,893  
Properties, plants and equipment (due primarily to tax in excess of book depreciation)
          (108,445 )     (108,445 )
Accrued postretirement benefits
    11,479             11,479  
Accrued environmental costs
    2,056             2,056  
Deferred turnaround costs
          (1,278 )     (1,278 )
Investments in HEP
    43,218             43,218  
Other
    14,037             14,037  
 
                 
Total noncurrent
    70,790       (109,723 )     (38,933 )
 
                 
Total
  $ 86,836     $ (122,876 )   $ (36,040 )
 
                 
 
(1)   Our net current deferred tax assets are classified as other current assets under “Prepayments and other” in our consolidated balance sheets.
We made income tax payments of $21.1 million in 2008, $139.4 million in 2007 and $142.9 million in 2006.

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The total amount of unrecognized tax benefits as of December 31, 2008, was $4.4 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
         
    Liability for  
    Unrecognized  
    Tax Benefits  
    (In thousands)  
Balance at January 1, 2008
  $ 3,539  
Additions based on tax positions related to the current year
    960  
Additions for tax positions of prior years
    479  
Reductions for tax positions of prior years
    (628 )
 
     
 
Balance at December 31, 2008
  $ 4,350  
 
     
Included in the unrecognized tax benefits at December 31, 2008 are $2.5 million of tax benefits that, if recognized, would affect our effective tax rate. Unrecognized tax benefits are adjusted in the period in which new information about a tax position becomes available or the final outcome differs from the amount recorded.
We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. During the year ended December 31, 2008, we recognized $0.8 million in interest (net of related tax benefits) as a component of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties. We do not expect that unrecognized tax benefits for tax positions taken with respect to 2008 and prior years will significantly change over the next twelve months.
We are subject to U.S. federal income tax, New Mexico income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through December 31, 2003. This includes a review by the Joint Committee on Taxation Staff of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003 that resulted in no changes to our positions taken on these returns. In 2008, the Internal Revenue Service commenced an examination of our U.S. federal income tax returns for the tax years ended December 31, 2004 and 2005. We anticipate that these audits will be completed by the end of 2009.
NOTE 13: Stockholders’ Equity
The following table shows our common shares outstanding and the activity during the year:
                         
    Years Ended December 31,  
    2008     2007     2006  
Common shares outstanding at beginning of year
    52,616,169       55,316,615       58,752,942  
Issuance of common stock upon exercise of stock options
    406,000       1,085,600       902,700  
Issuance of restricted stock, excluding restricted stock with performance feature
    104,515       230,196       51,952  
Vesting of restricted stock with performance feature
    84,948       151,000       119,000  
Forfeitures of restricted stock
    (2,033 )     (23,537 )     (4,984 )
Purchase of treasury stock(1)
    (3,266,379 )     (4,143,705 )     (4,504,995 )
 
                 
Common shares outstanding at end of year
    49,943,220       52,616,169       55,316,615  
 
                 
 
(1)   Includes shares purchased under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock.
Common Stock Repurchases: Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million or an average of $42.48 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.

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During the year ended December 31, 2008, we repurchased at market price from certain executives 55,515 shares of our common stock at a cost of $2.0 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.
NOTE 14: Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) are as follows:
                         
            Tax Expense        
    Before-Tax     (Benefit)     After-Tax  
    (In thousands)  
For the year ended December 31, 2008
                       
Minimum pension liability adjustment
  $ (21,572 )   $ (8,391 )   $ (13,181 )
Retirement medical obligation adjustment
    1,433       557       876  
Unrealized loss on available-for-sale securities
    (169 )     (67 )     (102 )
Unrealized loss on HEP cash flow hedge, net of minority interest
    (5,888 )     (2,290 )     (3,598 )
 
                 
Other comprehensive loss
  $ (26,196 )   $ (10,191 )   $ (16,005 )
 
                 
 
                       
For the year ended December 31, 2007
                       
Minimum pension liability adjustment
  $ (9,373 )   $ (3,647 )   $ (5,726 )
Retirement medical obligation adjustment
    (5,038 )     (1,960 )     (3,078 )
Unrealized gain on available-for-sale securities
    1,779       693       1,086  
 
                 
Other comprehensive loss
  $ (12,632 )   $ (4,914 )   $ (7,718 )
 
                 
 
                       
For the year ended December 31, 2006
                       
Minimum pension liability adjustment
  $ 5,542     $ 2,156     $ 3,386  
Unrealized loss on available-for-sale securities
    (908 )     (353 )     (555 )
 
                 
Other comprehensive income
  $ 4,634     $ 1,803     $ 2,831  
 
                 
The temporary unrealized gain (loss) on securities available-for-sale is due to changes in the market prices of securities.
Accumulated other comprehensive loss in the equity section of the balance sheet includes:
                 
    December 31,  
    2008     2007  
    (In thousands)  
Pension obligation adjustment
  $ (29,409 )   $ (16,228 )
Retiree medical obligation adjustment
    (2,202 )     (3,078 )
Unrealized gain on securities available-for-sale
    128       230  
Unrealized loss on HEP cash flow hedge, net of minority interest
    (3,598 )      
 
           
Accumulated other comprehensive loss
  $ (35,081 )   $ (19,076 )
 
           
NOTE 15: Retirement Plans
Retirement Plan: We have a non-contributory defined benefit retirement plan that covers substantially all employees. Our 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.
Effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an employee was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen.

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The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2008 and 2007:
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands)  
Change in plan’s benefit obligation
               
Pension plan’s benefit obligation — beginning of year
  $ 72,842     $ 62,107  
Service cost
    4,229       4,110  
Interest cost
    4,692       4,075  
Benefits paid
    (6,188 )     (5,806 )
Actuarial (gain) loss
    (1,087 )     8,356  
 
           
Pension plan’s benefit obligation — end of year
    74,488       72,842  
 
               
Change in pension plan assets
               
Fair value of plan assets — beginning of year
    56,454       50,414  
Actual return on plan assets
    (19,924 )     1,846  
Benefits paid
    (6,188 )     (5,806 )
Employer contributions
    15,000       10,000  
 
           
Fair value of plan assets — end of year
    45,342       56,454  
 
               
Funded status
               
Under-funded balance
  $ (29,146 )   $ (16,388 )
 
           
 
               
Amounts recognized in consolidated balance sheets Accrued pension liability
  $ (29,146 )   $ (16,388 )
 
           
 
               
Amounts recognized in accumulated other comprehensive loss Actuarial loss
  $ (43,475 )   $ (21,063 )
Prior service cost
    (3,201 )     (3,591 )
 
           
Total
  $ (46,676 )   $ (24,654 )
 
           
The accumulated benefit obligation was $58.7 million and $55.4 million at December 31, 2008 and 2007, respectively. The measurement dates used for our retirement plan were December 31, 2008 and 2007.
The weighted average assumptions used to determine end of period benefit obligations:
                 
    December 31,
    2008   2007
Discount rate
    6.50 %     6.40 %
Rate of future compensation increases
    4.00 %     4.00 %
Net periodic pension expense consisted of the following components:
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
Service cost — benefit earned during the year
  $ 4,229     $ 4,110     $ 4,270  
Interest cost on projected benefit obligations
    4,692       4,075       4,133  
Expected return on plan assets
    (4,793 )     (4,078 )     (3,473 )
Amortization of prior service cost
    390       390       258  
Amortization of net loss
    1,218       908       1,042  
Curtailment loss
                663  
Settlement loss
                1,589  
 
                 
Net periodic pension expense
  $ 5,736     $ 5,405     $ 8,482  
 
                 

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The weighted average assumptions used to determine net periodic benefit expense:
                         
    Years Ended December 31,
    2008   2007   2006
    (In thousands)
Discount rate
    6.40 %     6.00 %     6.05 %
Rate of future compensation increases
    4.00 %     4.00 %     4.00 %
Expected long-term rate of return on assets
    8.50 %     8.50 %     8.50 %
The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2009 are as follows:
         
    (In thousands)  
Actuarial loss
  $ 3,984  
Prior service cost
    390  
 
     
Total
  $ 4,374  
 
     
At year end, our retirement plan assets were allocated as follows:
                         
            Percentage of Plan Assets at
            Year End
    Target        
    Allocation   December 31,   December 31,
Asset Category   2009   2008   2007
Equity securities
    70 %     65 %     68 %
Debt Securities
    30 %     35 %     32 %
 
                 
Total
    100 %     100 %     100 %
 
                 
The investment policy developed for the Holly Corporation Pension Plan (the “Plan”) has been designed exclusively for the purpose of providing the highest probabilities of delivering benefits to Plan members and beneficiaries. Among the factors considered in developing the investment policy are: the Plans’ primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation.
The most important component of the investment strategy is the asset allocation between the various classes of securities available to the Plan for investment purposes. The current target asset allocation is 70% equity investments and 30% fixed income investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization and international stocks.
The overall expected long-term rate of return on Plan assets is 8.5% and is estimated using a financial simulation model of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient.
We expect to contribute between $10.0 million to $20.0 million to the retirement plan in 2009. Benefit payments, which reflect expected future service, are expected to be paid as follows: $4.6 million in 2009; $5.2 million in 2010; $5.9 million in 2011; $7.4 million in 2012, $7.6 million in 2013 and $50.4 million in 2014-2018.
Retirement Restoration Plan: We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. We expensed $1.1 million, $0.9 million and $0.8 million for the years ended December 31, 2008, 2007 and 2006, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.1 million and $6.6 million at December 31, 2008 and 2007, respectively. As of December 31, 2008, the projected benefit obligation under this plan was $6.1 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.2 million in 2009; $0.3 million in 2010; $0.9 million in 2011; $0.6 million in 2012; $1.4 million in 2013 and $2.9 million in 2014-2018.
Defined Contribution Plans: We have defined contribution “401(k)” plans that cover substantially all employees. Our contributions are based on employee’s compensation and partially match employee contributions. We expensed $3.7 million, $2.8 million and $1.9 million for the years ended December 31, 2008, 2007 and 2006, respectively, in connection with these plans.

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Postretirement Medical Plans: We adopted an unfunded postretirement medical plan as part of the voluntary early retirement program offered to eligible employees in fiscal 2000. As part of the early retirement program, we agreed to allow retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. The accrued liability reflected in the consolidated balance sheets was $6.7 million and $7.5 million at December 31, 2008 and 2007, respectively, related to this plan.
Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. Periodic costs under this plan have historically been insignificant.
As of December 31, 2008, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7 million.
NOTE 16: Lease Commitments
We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2008, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows (in thousands):
         
2009
  $ 8,825  
2010
    8,553  
2011
    7,483  
2012
    6,453  
2013
    6,382  
Thereafter
    22,839  
 
     
Total
  $ 60,535  
 
     
Rental expense charged to operations was $9.9 million, $3.2 million and $2.3 million for the years ended December 31, 2008, 2007 and 2006, respectively. Rental expense for the year ended December 31, 2008 includes $6.6 million of rental expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.
NOTE 17: Contingencies and Contractual Obligations
Contingencies
In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the FERC in proceedings brought by us and other parties against SFPP, 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. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals in its May 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. The income tax issue and the other remaining issues relating to SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding covering the period from 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. A partial settlement covering the period June 2006 through November 2007, which became final in February 2008, resulted in a payment from SFPP to us of approximately $1.3 million in April 2008. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through

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November 2010. The Commission approved the settlement on January 29, 2009. The settlement will reduce SFPP’s current rates and require SFPP to make additional payments to us of approximately $2.0 million.
We are a party to various other litigation and proceedings not mentioned in this report that we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.
Contractual Obligations
We have entered into a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices over a 15-year period commencing July 1, 2008. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term.
We also have two crude oil transportation agreements that obligate us to ship a total of approximately 21,000 barrels per day for initial terms of 10 years. Our obligations under these agreements are subject to certain conditions including completion of construction and expansion projects by the transportation companies, and the tariffs that will apply to these commitments have not been finalized. We expect approximately one-half of the total shipment commitment to begin no earlier than the fourth quarter of 2009 and the other one-half to begin no earlier than the fourth quarter of 2010.
Other contractual obligations relate to the transportation of natural gas and feedstocks to our refineries under contracts expiring in 2015 through 2023 and various service contracts with expiration dates through 2011.
NOTE 18: Segment Information
Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.
The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo and Woods Cross Refineries. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes Holly Asphalt Company which manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.
HEP is a VIE as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.
The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through their pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. The HEP segment also includes a 70% interest in Rio Grande which also provides petroleum products transportation services. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.

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                            Consolidations    
                    Corporate   and   Consolidated
    Refining   HEP(1)   and Other   Eliminations   Total
    (In thousands)
Year Ended December 31, 2008
                                       
Sales and other revenues
  $ 5,837,449     $ 101,750     $ 2,641     $ (74,172 )   $ 5,867,668  
Depreciation and amortization
  $ 40,090     $ 19,184     $ 4,515     $     $ 63,789  
Income (loss) from operations
  $ 210,252     $ 41,734     $ (51,654 )   $     $ 200,332  
Capital expenditures
  $ 381,227     $ 34,317     $ 2,515     $     $ 418,059  
Total assets
  $ 1,288,211     $ 458,049     $ 141,768     $ (13,803 )   $ 1,874,225  
 
                                       
Year Ended December 31, 2007
                                       
Sales and other revenues
  $ 4,790,164     $     $ 1,578     $     $ 4,791,742  
Depreciation and amortization
  $ 40,325     $     $ 3,131     $     $ 43,456  
Income (loss) from operations
  $ 537,118     $     $ (70,786 )   $     $ 466,332  
Capital expenditures
  $ 151,448     $     $ 9,810     $     $ 161,258  
Total assets
  $ 1,271,163     $     $ 392,782     $     $ 1,663,945  
 
                                       
Year Ended December 31, 2006
                                       
Sales and other revenues
  $ 4,021,974     $     $ 1,752     $ (509 )   $ 4,023,217  
Depreciation and amortization
  $ 38,156     $     $ 1,565     $     $ 39,721  
Income (loss) from operations
  $ 425,474     $     $ (63,583 )   $     $ 361,891  
Capital expenditures
  $ 105,018     $     $ 15,411     $     $ 120,429  
Total assets
  $ 940,400     $     $ 297,469     $     $ 1,237,869  
 
(1)   HEP segment revenues from external customers were $27.6 million for the year ended December 31, 2008.
NOTE 19: Significant Customers
All revenues were domestic revenues, except for sales of gasoline and diesel fuel for export into Mexico by the Refining segment. The export sales were to an affiliate of PEMEX and accounted for 325.4 million (6%) of our revenues in 2008, $200.0 million (5%) of our revenues in 2007 and $144.4 million (4%) of revenues in 2006. In 2008, 2007 and 2006, we had several significant customers, none of which accounted for more than 10% of our revenues.
NOTE 20: Quarterly Information (Unaudited)
                                         
    First   Second   Third   Fourth    
    Quarter   Quarter   Quarter   Quarter   Year
    (In thousands except share data)
Year Ended December 31, 2008
                                       
Sales and other revenues
  $ 1,479,984     $ 1,743,822     $ 1,719,920     $ 923,942     $ 5,867,668  
Operating costs and expenses
  $ 1,470,391     $ 1,723,596     $ 1,636,944     $ 836,405     $ 5,667,336  
Income from operations
  $ 9,593     $ 20,226     $ 82,976     $ 87,537     $ 200,332  
Income from continuing operations before income taxes
  $ 13,344     $ 17,308     $ 75,649     $ 79,083     $ 185,384  
Net income
  $ 8,649     $ 11,452     $ 49,899     $ 50,558     $ 120,558  
Net income per common share — basic
  $ 0.17     $ 0.23     $ 1.00     $ 1.02     $ 2.40  
Net income per common share — diluted
  $ 0.17     $ 0.23     $ 1.00     $ 1.01     $ 2.38  
Dividends per common share
  $ 0.15     $ 0.15     $ 0.15     $ 0.15     $ 0.60  
Average number of shares of common stock outstanding
                                       
Basic
    51,165       50,158       49,717       49,794       50,202  
Diluted
    51,515       50,515       50,032       49,997       50,549  

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    First   Second   Third   Fourth    
    Quarter   Quarter   Quarter   Quarter   Year
    (In thousands except share data)
Year Ended December 31, 2007
                                       
Sales and other revenues
  $ 925,867     $ 1,216,997     $ 1,208,671     $ 1,440,207     $ 4,791,742  
Operating costs and expenses
  $ 829,293     $ 980,447     $ 1,141,039     $ 1,374,631     $ 4,325,410  
Income from operations
  $ 96,574     $ 236,550     $ 67,632     $ 65,576     $ 466,332  
Income from continuing operations before income taxes
  $ 102,228     $ 244,763     $ 77,267     $ 75,186     $ 499,444  
Net income
  $ 67,542     $ 158,627     $ 58,126     $ 49,833     $ 334,128  
Net income per common share — basic
  $ 1.22     $ 2.89     $ 1.06     $ 0.92     $ 6.09  
Net income per common share — diluted
  $ 1.20     $ 2.84     $ 1.04     $ 0.90     $ 5.98  
Dividends per common share
  $ 0.10     $ 0.12     $ 0.12     $ 0.12     $ 0.46  
Average number of shares of common stock outstanding
                                       
Basic
    55,189       54,959       54,819       54,451       54,852  
Diluted
    56,318       55,953       55,853       55,098       55,850  

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We have had no change in, or disagreement with, our independent registered public accountants on matters involving accounting and financial disclosure.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
See Item 8 for “Management’s Report on its Assessment of the Company’s Internal Control Over Financial Reporting” and “Report of the Independent Registered Public Accounting Firm.”
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2008 that would need to be reported on Form 8-K that have not previously been reported.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and d(5) of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2009 and is incorporated herein by reference.
New York Stock Exchange Certification
In 2008, Matthew P. Clifton, as our Chief Executive Officer, provided to the New York Stock Exchange the annual CEO certification regarding our compliance with the New York Stock Exchange’s corporate governance listing standards.
Item 11. Executive Compensation
The information required by Item 402 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2009 and is incorporated herein by reference.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2009 and is incorporated herein by reference.
Item 13. Certain Relationships, Related Transactions and Director Independence
The information required by Item 404 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2009 and is incorporated herein by reference.
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 our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2009 and is incorporated herein by reference.

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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as part of this report
  (1)   Index to Consolidated Financial Statements
         
    Page in
    Form 10-K
Report of Independent Registered Public Accounting Firm
    64  
 
       
Consolidated Balance Sheets at December 31, 2008 and 2007
    65  
 
       
Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006
    66  
 
       
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006
    67  
 
       
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006
    68  
 
       
Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006
    69  
 
       
Notes to Consolidated Financial Statements
    70  
  (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
 
      See Index to Exhibits on pages 98 to 101.

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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/ Matthew P. Clifton    
  Matthew P. Clifton   
  Chief Executive Officer   
 
Date: February 27, 2009
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/ Matthew P. Clifton
 
     Matthew P. Clifton
  Chief Executive Officer and
Chairman of the Board
  February 27, 2009
 
       
/s/ Bruce R. Shaw
 
     Bruce R. Shaw
  Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)
  February 27, 2009
 
       
/s/ Scott C. Surplus
 
     Scott C. Surplus
  Vice President and Controller
(Principal Accounting Officer)
  February 27, 2009
 
       
/s/ Denise C. McWatters
 
     Denise C. McWatters
  Vice President, General
Counsel and Secretary
  February 27, 2009
 
       
/s/ Buford P. Berry
 
     Buford P. Berry
  Director    February 27, 2009
 
       
/s/ Leldon E. Echols
 
     Leldon E. Echols
  Director    February 27, 2009
 
       
/s/ Marcus R. Hickerson
 
     Marcus R. Hickerson
  Director    February 27, 2009
 
       
/s/ Robert G. McKenzie
 
     Robert G. McKenzie
  Director    February 27, 2009
 
       

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Signature   Capacity   Date
 
/s/ Thomas K. Matthews, II
 
     Thomas K. Matthews, II
  Director    February 27, 2009
 
       
/s/ Jack P. Reid
 
     Jack P. Reid
  Director    February 27, 2009
 
       
/s/ Paul T. Stoffel
 
     Paul T. Stoffel
  Director    February 27, 2009

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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
 
   
2.1
  Purchase and Sale Agreement, dated February 25, 2008 between Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C., Woods Cross Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 2.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed February 27, 2008, File No. 1-32225).
 
   
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+
  Certificate of Amendment to the Restated Certificate of Incorporation of Holly Corporation, adopted May 26, 2004.
 
   
3.3+
  Certificate of Amendment to the Restated Certificate of Incorporation of Holly Corporation, adopted May 29, 2007.
 
   
3.4
  By-Laws of Holly Corporation as amended and restated December 22, 2005 (incorporated by reference to Exhibit 3.2.2 of Registrant’s Current Report on Form 8-K filed December 22, 2005, File No. 1-3876).
 
   
4.1
  Indenture, dated February 28, 2005, among Holly Energy Partners, L.P. and Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).
 
   
4.2
  Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).
 
   
4.3
  Form of Notation of Guarantee (included as Exhibit E to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225).
 
   
4.4
  First Supplemental Indenture, dated March 10, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225).
 
   
4.5
  Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225).
 
   
10.1
  Option Agreement, dated January 31, 2008, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 5, 2008, File No. 1-03876).

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Exhibit    
Number   Description
 
   
10.2
  Pipelines and Tankage Agreement, dated February 29, 2008, between Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C., Woods Cross Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 6, 2008, File No. 1-32225).
 
   
10.3*
  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).
 
   
10.4*+
  Holly Corporation Long-Term Incentive Compensation Plan as amended and restated on May 24, 2007 as approved at the annual meeting of stockholders of Holly Corporation on May 24, 2007.
 
   
10.5*+
  Amendment No. 1 to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated on May 24, 2007.
 
   
10.6*
  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).
 
   
10.7*
  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).
 
   
10.8*
  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).
 
   
10.9*
  Form of Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).
 
   
10.10*+
  First Amendment to Restricted Stock Unit Agreement dated May 11, 2006.
 
   
10.11*
  Form of Executive Restricted Stock Agreement [two-year term vesting form] (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).
 
   
10.12*
  Form of Executive Restricted Stock Agreement [two-year term and performance vesting form] (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).

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Exhibit    
Number   Description
 
   
10.13*
  Form of Executive Restricted Stock Agreement [five-year term vesting form] (incorporated by reference to Exhibit 10.4 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).
 
   
10.14*
  Form of Executive Restricted Stock Agreement [five-year term and performance vesting form] (incorporated by reference to Exhibit 10.5 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876).
 
   
10.15*
  Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed January 12, 2007, File No. 1-3876).
 
   
10.16+
  First Amendment to Performance Share Unit Agreement.
 
   
10.17
  Holly Corporation Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-3876).
 
   
10.18
  Holy Corporation Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-3876).
 
   
10.19
  Holly Energy Partners, L.P. Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-3876).
 
   
10.20
  Amended and Restated Credit Agreement dated March 14, 2008, between Holly Corporation, Bank of America, N.A., as administrative agent and L/C issuer, PNC Bank, National Association and Guaranty Bank, as co-documentation agents, Union Bank of California, N.A. and Compass Bank, as co-syndication agents, and certain other lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed March 20, 2008, File No. 1-3876).
 
   
10.21
  Guarantee and Collateral Agreement, dated July 1, 2004, among Holly Corporation and certain of its Subsidiaries in favor of Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-3876).
 
   
10.22+
  Reaffirmation and Assumption Agreement dated March 14, 2008, among Holly Corporation, the subsidiaries identified therein, the additional grantors identified therein and Bank of America, N.A. (adding additional grantors under the Guaranty and Collateral Agreement included as Exhibit 10.22 above).
 
   
10.23
  Amended and Restated Credit Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger, Bank of America, N.A., as syndication agent, Guaranty Bank, as documentation agent and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed October 31, 2007, File No. 1-32225).
 
   
10.24
  Agreement and Amendment No. 1 to Amended and Restated Credit Agreement, dated February 25, 2008, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners’ Current Report on Form 8-K filed February 27, 2008, File No. 1-32225).

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Exhibit    
Number   Description
 
   
10.25
  Amendment No. 2 to Amended and Restated Credit Agreement, dated September 8, 2008, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries acting as guarantors, Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.11 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q filed October 31, 2008, File No. 1-32225).
 
   
10.26
  Amended and Restated Pledge Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.12 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225).
 
   
10.27
  Amended and Restated Guaranty Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.13 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225)
 
   
10.28
  Amended and Restated Security Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.14 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225)
 
   
10.29
  Form of Mortgage, Deed of Trust, Security Agreement, Assignment of Rents and Leases, Fixture Filing and Financing Statement (for purposes of granting security interests in real property in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.15 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225)
 
   
10.30*
  Form of Indemnification Agreement entered into with directors and officers of Holly Corporation (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed December 13, 2006, File No. 1-3876).
 
   
21.1+
  Subsidiaries of Registrant.
 
   
23.1+
  Consent of Independent Registered Public Accounting Firm.
 
   
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.
 
+   Filed herewith.
 
*   Constitutes management contracts or compensatory plans or arrangements.

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