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, 20082009
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)
   
Delaware75-1056913

(State or other jurisdiction of		(I.R.S Employer

incorporation or organization)		 75-1056913
(I.R.S Employer
Identification No.)
   
100 Crescent Court, Suite 1600, Dallas, Texas75201-6915

(Address of principle executive offices)		 75201-6915
(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.
Yesþ Noo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.
Yeso Noþ
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.Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yeso Noo
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 filerþ
 Accelerated filero Non-accelerated filero Smaller reporting companyo
(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).
Yeso Noþ
On June 30, 20082009 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $1,494$746 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.)
50,069,99853,103,336 shares of Common Stock, par value $.01 per share, were outstanding on February 6, 2009.8, 2010.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 14, 2009,5, 2010, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2008,2009, are incorporated by reference in Part III.
 
 

 

 

TABLE OF CONTENTS
     
Item Page
Item
 
     
PART I
     
Forward-Looking StatementsForward-looking statements
  3 
     
Definitions
  4 
     
1 and 2. Business and properties
  78
 
1A. Risk factors
  2227
 
1B. Unresolved staff comments
  3139
 
3. Legal proceedings
  3139
 
4. Submission of matters to a vote of security holders
  3442 
     
PART II
     
5. Market for the Registrant’s common equity, related stockholder matters and issuer purchases of equity securities
  3543
 
6. Selected financial data
  3644
 
7. Management’s discussion and analysis of financial condition and results of operations
  3745
 
7A. Quantitative and qualitative disclosures about market risk
  5565 
 
Reconciliations to amounts reported under generally accepted accounting principles
  5565 
 
8. Financial statements and supplementary data
  6171
 
9. Changes in and disagreements with accountants on accounting and financial disclosure
  93115
 
9A. Controls and procedures
  93
9B. Other information
93115 
     
PART III9B. Other information
115
    
PART III
     
10. Directors, executive officers and corporate governance
  93115
 
11. Executive compensation
  93115
 
12. Security ownership of certain beneficial owners and management and related stockholder matters
  94116
 
13. Certain relationships, related transactions and director independence
  94116
 
14. Principal accountant fees and services
  94116 
     
PART IV
     
15. Exhibits and financial statement schedules
  95117 
     
Signatures
  96118 
     
Index to exhibits
  98119
 
 EX-3.2Exhibit 4.8
 EX-3.3Exhibit 4.9
 EX-10.4Exhibit 4.10
 EX-10.5Exhibit 4.11
 EX-10.10Exhibit 21.1
 EX-10.16Exhibit 23.1
 EX-10.22Exhibit 31.1
 EX-21.1Exhibit 31.2
 EX-23.1Exhibit 32.1
 EX-31.1
EX-31.2
EX-32.1
EX-32.2Exhibit 32.2

-2-

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 beliefbeliefs 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.
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 and environmental 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 existing or 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.

-3-

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).
“Aromatic oil” is long chain oil that is highly aromatic in nature that is used to manufacture tires and in the production of asphalt.
“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”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.
“Delayed coker unit” is a refinery unit that removes carbon from the bottom cuts of crude oil to produce unfinished light transportation fuels and petroleum coke.
“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.

-4-

“LSG,” or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.
“MMBtuLube extraction unit” is a unit used in the lube process that separates aromatic oils from paraffinic oils using furfural as a solvent.
“Lubricant” or one million British thermal units,“lube” means a solvent neutral paraffinic product used in passenger and commercial vehicle engine oils, specialty products for each unit, the amount ofmetal working or heat required to raise one pound of water one degree Fahrenheit at one atmosphere pressure.transfer applications and other industrial applications.
“MEK” means a lube process that separates waxy oil from non-waxy oils using methyl ethyl ketone as a solvent.
“MMSCFD” means one million standard cubic feet per day.

-4-

“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.
“Parafinnic oil” is a high paraffinic, high gravity oil produced by extracting aromatic oil and waxes from gas oil and is used in producing high-grade lubricating oils.
“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.
“Roofing flux” is produced from the bottom cut of crude oil and is the base oil used to make roofing shingles for the housing industry.
“ROSE,”, or “Solvent“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.
“Scanfiner” is a refinery unit that removes sulfur from gasoline to produce low sulfur gasoline blendstock.
“Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet“sweet crude oil”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.

-5-

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 ACT49 
2005 ACT  4958
ACESA31
Agreement42
Alon PTA23 
Amended NOV  3241 
AOCBeeson Pipeline  3222 
CAA  2025 
CERCLA  2126 
ConnacherCWA  826
Centurion Pipeline22 
Court of Appeals  31
Credit Agreement4540 
Crude Pipelines and Tankage Assets  7
CWA20
DESC138 
EBITDA  4047 
EPA  1314 
Exchange Act  94
FASB7115 
FERC  17
FIN723 
Fixed Rate Swap  5463 
GAAP  8 
Guarantor Restricted Subsidiaries106
HEP  78 
HEP CPTA  1723
HEP ETA22
HEP IPA22
HEP PTA23
HEP PTTA22
HEP RPA22 
HEP Credit Agreement  4553 
HEP IPAPipeline Operating Agreement  17
HEP PTA1723 
HEP Senior Notes  4654 
Holly Asphalt  119
Holly Credit Agreement53 
HPI  1950
HRM-Tulsa42 
LIBOR  5462 
LIFO  3037 
MDEQ  3241 
MontanaMRC41
MSAT214
Magellan12
NEP41
NMED41
NPDES26
Navajo Refinery9
Non-Guarantor Non-Restricted Subsidiaries106
Non-Guarantor Restricted Subsidiaries106
ODEQ42
OSHA41
Plains8
Plan103
PPI23
PSM42
RCRA26
Restricted Subsidiaries106
Rio Grande22
Roadrunner Pipeline22
SEC8
SDWA26
SFPP12
SLC Pipeline9
Sinclair8
Sinclair Tulsa42
Sunoco8

-6-

Page
Reference
Tulsa Refinery  8 
NavajoTulsa Refinery east facility  78 
NEPTulsa Refinery west facility  33
NMED32
NPDES20
Ominbus Agreement13
OSHA33
PEMEX9
Plains11
Plan89
PPI17
Rio Grande7
Rocky Mountain33
SEC7
SDWA20
SFAS53
SFPP11
SLC Pipeline19
South System198 
UNEV Pipeline  169 
UOSH  3341 
Variable Rate Swap  5462 
VIE  7
VRDN458 
Woods Cross Refinery  79 
WRB  1112 
Terms used in the financial statements and footnotes are as defined therein.

-6-

-7-

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, jet fuel, specialty lubricant products, and jet fuel.specialty and modified asphalt. 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 iswww.hollycorp.com. 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,On June 1, 2009, we completedacquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate Sunoco, Inc. (“Sunoco”) for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in 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 allMid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage tanks and certain refining-related crude oil receiving pipeline facilities, that were acquired as part of the refinery assets for $40 million.
On December 1, 2009, we acquired a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company (“Sinclair”) also located in Tulsa, Oklahoma (the “Tulsa Refinery east facility”) for $183.3 million, including crude oil, refined product pipeline and terminalling assets that supportother inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our refiningcommon stock having a value of $74 million. Additionally, we will reimburse Sinclair approximately $8 million upon their satisfactory completion of certain environmental projects at the refinery. The refinery also produces gasoline, diesel fuel and marketingjet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”of both Tulsa Refinery facilities (collectively, the “Tulsa Refinery”). Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.
On February 29, 2008, we closed on the sale ofsold certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0$180 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 BoardU.S. generally accepted accounting principles (“FASB”GAAP”) Interpretation (“FIN”) No. 46R.. Under the provisions of FIN No. 46R,GAAP, 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.our beneficial interest in HEP. Following this transfer,transaction, we determined that HEP continued to qualify as a VIE, and furthermore, we

-8-

determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for2008. Therefore, intercompany transactions with HEP are eliminated in our investmentconsolidated financial statements.
HEP had a number of acquisitions in HEP2009. Information on these acquisitions can be found under the equity method“Holly Energy Partners, L.P.�� section provided later in this discussion of accounting.Items 1 and 2, “Business and Properties.”
As of December 31, 2008,2009, we:
owned and operated twothree 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 (“(the “Woods Cross Refinery”) and the Tulsa Refinery;
owned and operated Holly Asphalt Company (formerly, NK Asphalt Partners) which manufactures and markets asphalt products from various terminals in Arizona, New Mexico and Texas;
owned a 75% interest in a 12-inch refined products pipeline project 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”); and
owned a 34% interest in HEP (which includes our 2% general partnership interest), which owns and operates logistics assets including approximately 2,500 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; four refinery loading rack facilities; a refined products tank farm facility; on-site crude oil tankage at our Navajo, Woods Cross Refinery”and Tulsa Refineries, on-site refined product tankage at our Tulsa Refinery and a 25% interest in a 95-mile, crude oil pipeline joint venture (the “SLC Pipeline”);.

-7-

•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 85,000100,000 BPSD, can process up to approximately 90%100% 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 facilityThe Woods Cross Refinery is a high conversion refinery that processes regional sweet and Canadian sour crude oils.
On March 31, 2006 we soldoils and serves markets in Utah, Idaho, Nevada, Wyoming, Wyoming and eastern Washington. Our Tulsa Refinery located in Tulsa, Oklahoma has a crude capacity of 125,000 BPSD and is owned and operated by Holly Refining & Marketing Company — Tulsa LLC, one of our petroleum refinery in Great Falls, Montana (the “Montana Refinery”)wholly-owned subsidiaries. The Tulsa Refinery primarily processes sweet crude oils, however has the capability to a subsidiary of Connacher Oilprocess sour crude oils when economics dictate, and Gas Limited (“Connacher”). Accordingly,serves the results of operationsMid-Continent region of the Montana Refinery and a net gain of $14.0 million on the sale are shown in discontinued operations.United States.
Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our Navajo, Refinery, Woods Cross Refineryand Tulsa Refineries and Holly Asphalt Company.Company (“Holly Asphalt”). Information regarding Holly Asphalt can be found under our discussion of the Navajo Refinery provided under the “Refinery Operations” section provided below. 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.operations of our three refineries. 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”).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%
          
             
  Years Ended December 31, 
  2009  2008  2007 
Consolidated
            
Crude charge (BPD)(1)
  142,430   100,680   103,490 
Refinery production (BPD)(2)
  151,420   110,850   113,270 
Sales of produced refined products (BPD)  151,580   111,950   115,050 
Sales of refined products (BPD)(3)
  155,820   120,750   126,800 
             
Refinery utilization(4)
  78.9%  89.7%  94.1%

-8-

-9-

             
  Years Ended December 31, 
  2009  2008  2007 
Average per produced barrel(5)
            
Net sales $74.06  $108.83  $89.77 
Cost of products(6)
  66.85   97.87   73.03 
          
Refinery gross margin  7.21   10.96   16.74 
Refinery operating expenses(7)
  5.24   5.14   4.43 
          
Net operating margin $1.97  $5.82  $12.31 
          
             
Feedstocks:            
Sour crude oil  49%  63%  62%
Sweet crude oil  40%  23%  23%
Black wax crude oil  5%  4%  3%
Other feedstocks and blends  6%  10%  12%
          
Total  100%  100%  100%
          
(1) Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
 
(2) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
 
(3) Includes refined products purchased for resale.
 
(4) Represents crude charge divided by total crude capacity (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 (our 2007 Navajo Refinery expansion) and by an additional 5,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion). During 2009, we increased our consolidated crude capacity by 15,000 BPSD in the first quarter of 2009 (our 2009 Navajo Refinery expansion), by 85,000 BPSD in second quarter of 2009 (our June 2009 Tulsa Refinery west facility acquisition) and by 40,000 BPSD in the fourth quarter of 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 116,000256,000 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,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
Consolidated
  
Sales of produced refined products:  
Gasolines  58%  60%  61%  51%  58%  60%
Diesel fuels  32%  29%  28%  31%  32%  29%
Jet fuels  1%  2%  3%  4%  1%  2%
Fuel oil  3%  4%  3%  2%  3%  4%
Asphalt  3%  2%  2%  2%  3%  2%
Lubricants  4%  —%  —%
Gas oil / intermediates  4%  —%  —%
LPG and other  3%  3%  3%  2%  3%  3%
              
Total  100%  100%  100%  100%  100%  100%
              
We have several significant customers, none of which accountsaccounted for more than 10% of our business.business in 2009. However, in conjunction with our refinery acquisition from Sinclair we have entered into a refined products purchase agreement, or offtake agreement, with an affiliate of Sinclair. Information on this offtake agreement can be found under our discussion of the Tulsa Refinery provided later in this section of “Refinery Operations.” 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 domesticcommercial airline use. Specialty lubricant products are sold in both commercial and specialty markets. 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.

-10-

Navajo Refinery
Facilities
The Navajo Refinery has a current crude oil capacity of 85,000100,000 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%92% of its raw materials throughput into high value light products. For 2008,2009, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 57%58%, 33%32% and 1%2%, 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.

-9-

             
  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%
          
             
  Years Ended December 31, 
  2009  2008  2007 
Navajo Refinery
            
Crude charge (BPD)(1)
  78,160   79,020   79,460 
Refinery production (BPD)(2)
  86,760   88,680   87,930 
Sales of produced refined products (BPD)  87,140   89,580   88,920 
Sales of refined products (BPD)(3)
  90,870   97,320   100,460 
             
Refinery utilization(4)
  81.2%  93.0%  94.6%
             
Average per produced barrel(5)
            
Net sales $73.15  $108.52  $89.68 
Cost of products(6)
  65.95   98.97   74.10 
          
Refinery gross margin  7.20   9.55   15.58 
Refinery operating expenses(7)
  4.81   4.58   4.30 
          
Net operating margin $2.39  $4.97  $11.28 
          
             
Feedstocks:            
Sour crude oil  85%  79%  82%
Sweet crude oil  6%  10%  9%
Other feedstocks and blends  9%  11%  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 theour refinery.
 
(3) Includes refined products purchased for resale.
 
(4) Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased from 75,00083,000 BPSD to 83,00085,000 BPSD during 2006in mid-year 2007 (our 2007 Navajo Refinery expansion) and by an additional 2,00015,000 BPSD in mid-year 2007,the first quarter of 2009 (our 2009 Navajo Refinery expansion), increasing crude capacity to 85,000100,000 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 theour refinery, exclusive of depreciation and amortization.
The Navajo Refinery’s Artesia, New Mexico facility is located on a 561 acre561-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 2.02 million barrels of feedstock and product tankage at the site of which 0.2 million isbarrels of tankage are 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 integrateda 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 isbarrels of tankage are owned by HEP. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of twothree 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 Refinery facilities is 85,000100,000 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 The Navajo Refinery facilities.completed a major maintenance turnaround in February 2009.

-11-

We distribute refined products from the Navajo Refinery to markets in Arizona, New Mexico, and west Texas and northern Mexico primarily through two of HEP’s owned pipelines that extend from Artesia, New Mexico to El Paso, Texas.Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Plains and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan’s subsidiary, SFPP, L.P. (“SFPP”). In addition, we use pipelines owned and leased by HEP to transport petroleum products to markets in central and

-10-

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.
Holly Asphalt Company
We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Texas and northern Mexico under Holly Asphalt Company (“Holly Asphalt”).Asphalt. We have threefour manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico, and Artesia, New Mexico.Mexico and Lubbock, Texas. Our Albuquerque, Artesia and ArtesiaLubbock facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo Refinery and third-party suppliers. Our Lubbock facility is leased under a lease agreement expiring in 2011. 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, which has historically experienced a high growth rate, 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”).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,and 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,are owned by Magellan Midstream Partners, L.P. (“Magellan”), NuStar Energy L.P. and HEP pipelines.HEP. Refined products from the Gulf Coast are transported via theMagellan pipelines, including Magellan’s Longhorn and Magellan pipelines.Pipeline acquired in 2009. We currently supply approximately 11,000 BPD to the El Paso market, which accounts for approximately 18%17% — 20% of the refined products consumed in thatthe El Paso 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 the West Coast. We currently supply approximately 52,000 BPD17% — 20% of the refined products via the SFPP Pipeline intoconsumed in the Arizona market, comprised primarily of Phoenix and Tucson, which accounts for approximately 17% ofvia the refined products consumed in that market.SFPP Pipeline.
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 Refining, Alon and WRB. We currently supply approximately 22,000 BPD of refined products to the New Mexico market, which accounts for approximately18% — 20% of the refined products consumed in thatthe New Mexico market.

-12-

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 Pipelineleased 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 ofship light products to the growing Albuquerque and Santa Fe, New Mexico areas.areas, which have historically experienced high growth rates. If needed, additional pump stations could further increase the pipeline’s capabilities.
TheMagellan’s 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

-11-

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. CrudeAdditionally, 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.
Additionally, the Navajo Refinery has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP’s Roadrunner Pipeline that connects to Centurion Pipeline L.P.’s pipeline running from west Texas to Cushing Oklahoma. Cushing Oklahoma is a significant crude oil pipeline crossroad and storage hub that has access to regional crude production as well as many United States onshore, Gulf of Mexico, Canadian and other foreign crudes.
We also purchase volumes of 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 usedRefinery from sources in the Navajo Refinery’s operations were purchased from a newly operational fractionation facility in Hobbs,southeastern New Mexico which is owned by Enterprise Products, L.P. as well as volumes purchased fromand the mid-continentMid-Continent area andthat are 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-mileintermediate 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 theour Navajo Refinery:
                        
 Years Ended December 31, Years Ended December 31, 
 2008 2007 2006 2009 2008 2007 
Navajo Refinery
  
Sales of produced refined products:  
Gasolines  57%  59%  60%  58%  57%  59%
Diesel fuels  33%  30%  28%  32%  33%  30%
Jet fuels  1%  3%  4%  2%  1%  3%
Fuel oil  3%  3%  2%  3%  3%  3%
Asphalt  3%  2%  3%  3%  3%  2%
LPG and other  3%  3%  3%  2%  3%  3%
              
Total  100%  100%  100%  100%  100%  100%
              
Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.

-13-

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 and commercial airline use. All asphalt produced atand purchased from third-parties is blended to fuel oil and is either sold locally, or is shipped by rail to the Navajo Refinery and third-party purchased asphalt isGulf Coast, shipped by rail directly to our customers or marketed through Holly Asphalt to governmental entities, contractors or contractors.manufacturers. 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,

-12-

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 inOur total approved capital expenditures in recent years to expand and enhancebudget for the Navajo Refinery for 2010 is $16.7 million. Additionally, capital costs of $11.5 million have been approved for refinery turnarounds and expand our supply and distribution network.
Our Board of Directors approved atank work. We expect to spend approximately $58.5 million in capital budget for 2009 of $11.4 million for refining improvement projects at the Navajo Refinery, notcosts in 2010, including the capital projects approved in prior years oryears. The following summarizes our expansion and feedstock flexibility projects described below.key capital projects.
At thePhase I of our Navajo Refinery we are proceeding with major capital projects including expandingwas mechanically completed in March 2009 increasing 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.effective April 1, 2009. Phase I requiresrequired 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 totalunits at a cost of approximately $190 million.
We are nearing completion of phase I is now expectedII of the major capital projects at the Navajo Refinery. These improvements will provide the capability to be approximately $185.0 million. The added costs are associated with permit timing delays, scope changes dueprocess up to permit required pollution control equipment that was not anticipated, material cost escalation and increased labor rates.
40,000 BPSD of heavy type crudes. 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 mechanicallyThe solvent deasphalter unit was complete in the fourth quarter of 2009 and was originally estimated to cost $84.0 million.is in operation. The total cost of phase IIcrude / vacuum unit revamp is now expected to be to be completed in the first quarter of 2010. We expect the phase II project to cost approximately $96.0$100 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$21 million and are expected to be completed atabout 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.projects.
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 theirits 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 U.S. Environmental Protection Agency (“EPA”).
In July 2008,The Navajo Refinery currently plans to comply with new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations issued by the EPA by the fractionation of raw naphtha with existing equipment to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will purchase credits from the Woods Cross and Tulsa Refineries in order reduce benzene down to the required 0.62%. Due to our acquisition of the Tulsa Refinery facilities from Sunoco and Sinclair, our Navajo Refinery has until the end of 2012 to comply with the MSAT2 regulation because we announced an agreement by one ofhave lost our subsidiariessmall refiner’s exemption and as a large refiner we have 30 months to transport crude oil on Centurion’s pipeline from Cushing, Oklahoma to its Slaughter Station located in west Texas. Our Board of Directors hascomply.
Additionally, our total 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 facilitybudget for processing. This will permit the segregation of heavy crude oilHolly Asphalt 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 2009.2010 is $1.2 million.

-13-

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 —located in Woods Cross, one of our wholly owned subsidiaries.Utah. 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 2008,2009, gasoline and diesel fuel (excluding volumes purchased for resale) represented 63%64% and 29%28%, respectively, of the Woods Cross Refinery’s sales volumes.

-14-

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 Reported 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%
          
             
  Years Ended December 31, 
  2009  2008  2007 
Woods Cross Refinery
            
Crude charge (BPD) (1)
  24,900   21,660   24,030 
Refinery production (BPD)(2)
  25,750   22,170   25,340 
Sales of produced refined products (BPD)  26,870   22,370   26,130 
Sales of refined products (BPD)(3)
  27,250   23,430   26,340 
             
Refinery utilization(4)
  80.3%  79.5%  92.4%
             
Average per produced barrel(5)
            
Net sales $70.25  $110.07  $90.09 
Cost of products(6)
  58.98   93.47   69.40 
          
Refinery gross margin  11.27   16.60   20.69 
Refinery operating expenses(7)
  6.60   7.42   4.86 
          
Net operating margin $4.67  $9.18  $15.83 
          
             
Feedstocks:            
Sour crude oil  5%  1%  2%
Sweet crude oil  62%  72%  75%
Black wax crude oil  28%  21%  15%
Other feedstocks and blends  5%  6%  8%
          
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 theour 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 (our 2008 Woods Cross Refinery expansion), 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 acre200-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 isbarrels of tankage are 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

-14-

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. The Woods Cross Refinery completed a major maintenance turnaround in September 2008.
We own and operate 24 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 allowallows us to connect our Woods Cross Refinery to common carrier pipeline systems.

-15-

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%50% — 55% 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% — 20% of the refined products consumed in thatthe Utah 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 thosethe combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery 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.

-15-

Principal Products and Customers
Set forth below is information regarding the principal products produced at theour Woods Cross Refinery:
                        
 Years Ended December 31, Years Ended December 31, 
 2008 2007 2006 2009 2008 2007 
Woods Cross Refinery
  
Sales of produced refined products:  
Gasolines  63%  63%  63%  64%  63%  63%
Diesel fuels  29%  27%  28%  28%  29%  27%
Jet fuels  —%  2%  2%  1%  —%  2%
Fuel oil  5%  5%  5%  3%  5%  5%
Asphalt  1%  1%  —%  2%  1%  1%
LPG and other  2%  2%  2%  2%  2%  2%
              
Total  100%  100%  100%  100%  100%  100%
              

-16-

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 isare sold for domesticcommercial airline use. All asphaltAsphalt produced is either blended to fuel oil andor is sold locally, railedor shipped by rail to the Gulf Coast, railedshipped by rail 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. In 2009, we also began receiving crude oil via the SLC Pipeline, a joint venture common carrier pipeline in which HEP owns a 25% interest. Supplies of black wax crude oil are shipped via truck.
Capital Improvement Projects
Our total approved capital budget for 2009 capital projects at the Woods Cross Refinery for 2010 is $5.3$36.4 million. Additionally, capital costs of $3.3 million nothave been approved for refinery turnarounds and tank work. We expect to spend approximately $12.6 million in capital costs in 2010, including the major projects described below or other capital projects approved in prior years. The following summarizes our key capital projects.
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.$122 million. The projects were completedmechanically complete in the fourth quarter of 2008. These improvements
Our Woods Cross Refinery is required to install a wet gas scrubber on its FCC unit by the end of 2012. We estimate the total cost to be $12 million. The MSAT2 solution for Woods Cross involves installing a new reformate splitter and a benzene saturation unit at an estimated cost of $18 million. Like our Navajo Refinery, our Woods Cross Refinery has until the end of 2012 to comply with the MSAT2 regulations.
Tulsa Refinery
Facilities
On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery in Tulsa, Oklahoma from Sunoco. On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BSPD refinery that is also located in Tulsa, Oklahoma from Sinclair. We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will also providehave an integrated crude processing rate of 125,000 BPSD.
The Tulsa Refinery primarily processes sweet crude oils into high value light products such as gasoline, diesel fuel, jet fuel and lubricants, however has the necessarycapability to process sour crude oils when economics dictate. For 2009, gasoline, diesel fuel, jet fuel and lubricants (excluding volumes purchased for resale) represented 26%, 29%, 10% and 16%, respectively, of the Tulsa Refinery’s sales volumes.

-17-

The following table sets forth information about the Tulsa 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 Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
     
  Year Ended 
  December 31, 
  2009(8) 
Tulsa Refinery
    
Crude charge (BPD) (1)
  39,370 
Refinery production (BPD)(2)
  38,910 
Sales of produced refined products (BPD)  37,570 
Sales of refined products (BPD)(3)
  37,700 
     
Refinery utilization(4)
  74.0%
     
Average per produced barrel(5)
    
Net sales $78.89 
Cost of products(6)
  74.56 
    
Refinery gross margin  4.33 
Refinery operating expenses(7)
  5.25 
    
Net operating margin $(0.92)
    
     
Feedstocks:    
Sweet crude oil  100%
(1)Crude charge represents the barrels per day of crude oil processed at our refinery.
(2)Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refinery.
(3)Includes refined products purchased for resale.
(4)Represents crude charge divided by total crude capacity (BPSD). The crude capacity of 85,000 BPSD (our June 2009 Tulsa Refinery west facility acquisition) was increased by 40,000 BPSD in the fourth quarter of 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing crude capacity to 125,000 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.
(8)The amounts reported for the Tulsa Refinery for the year ended December 31, 2009 include crude oil processed and products yielded from the refinery for the period from June 1, 2009 through December 31, 2009 only, and averaged over the 365 days for the year ended. Operating data for the period from June 1, 2009 (date of Tulsa Refinery west facility acquisition) through December 31, 2009 and for the period from December 1, 2009 (date of Tulsa Refinery east facility acquisition) through December 31, 2009 is as follows:
         
  Period From  Period From 
  June 1, 2009  December 1, 2009 
  Through  Through 
  December 31, 2009  December 31, 2009 
Tulsa Refinery
        
Crude charge (BPD)  67,160   93,810 
Refinery production (BPD)  66,360   99,810 
Sales of produced refined products (BPD)  64,080   96,170 
Sales of refined products (BPD)  64,300   96,170 
The Tulsa Refinery west facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa Refinery west facility consist of crude distillation (with light ends recovery), naphtha hydrodesulfurization, catalytic reforming, propane de-asphalting, lube extraction unit, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. The refinery completed a major maintenance turnaround in July 2007. The refinery’s supporting infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains, and an additional 1.2 million barrels of tank capacity that are currently out of service and could be made available for future expansionsuse.

-18-

The Tulsa Refinery east facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa Refinery east facility consist of crude distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. Additions and improvements to the facility since late 2004 include a scanfining unit to meet 2006 gasoline sulfur content requirements, a new naphtha hydro desulphurizer unit in 2005, a new sulfur plant, modifications to the distillate hydro desulphurizer unit, a new tail gas unit installed on the new sulfur plant and the conversion of the reformer from a 17,000 BPD semi-regenerative reformer to a 22,000 BPD continuous catalyst regeneration reformer (thereby increasing its capacity, octane capability and enableyield of gasoline). The refinery completed a partial maintenance turnaround in 2007, including the crude and FCC units. The refinery’s supporting infrastructure includes approximately 3.75 million barrels of tankage capacity on the refinery’s premises, approximately 1.4 million barrels of which is owned by HEP.
We are integrating the Tulsa Refinery west and east facilities that will result in a single, highly complex refinery having an integrated crude processing rate of approximately 125,000 BPSD, primarily by sending intermediate streams from one facility to the other for further processing. Pursuant to this plan, high sulfur diesel and various gas oil streams will be sent from the Tulsa Refinery west facility to be processed in the diesel hydrotreater and FCC units, respectively, at the Tulsa Refinery east facility. Various heavy oil streams will be sent from the Tulsa Refinery east facility to be processed in our coker unit at our Tulsa Refinery west facility. Various other streams such as naphtha, hydrogen and fuel gas will be shared between the two refinery facilities.
The Tulsa Refinery produces fuel products including gasoline, diesel fuel, jet fuel, #1 fuel oil, asphalt, heavy fuels and LPGs and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America.
Markets and Competition
The Tulsa Refinery primarily serves the Mid-Continent region of the United States. Distillates and gasolines are primarily delivered from the Tulsa Refinery to market via two pipelines owned and operated by Magellan. These pipelines connect the refinery to meetdistribution channels throughout Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, the Tulsa Refinery has a proprietary diesel transfer line to the local Burlington Northern Santa Fe Railroad depot, and the refinery’s truck and rail rack capability facilitates access to local refined product markets.
In conjunction with our acquisition of the Tulsa Refinery east facility, we entered a five-year offtake agreement with an affiliate of Sinclair whereby Sinclair has agreed to purchase 45,000 to 50,000 BPD of gasoline and distillate products at market prices from us to supply its branded and unbranded marketing network throughout the Midwest. The offtake agreement can be renewed by Sinclair for an additional five-year term.
Our Tulsa Refinery also produces specialty lubricant products including agricultural oils, base oils, process oils and waxes that are sold throughout the United States and to customers with operations in Central America and South America. Our refinery’s production represents 6% of paraffinic oil capacity and 12% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.
The refinery’s asphalt and roofing flux products are sold via truck or railcar directly from the refinery or from a leased terminal in Phillipsburg, Kansas to customers throughout the Mid-Continent region.
Principal Products and Customers
Set forth below is information regarding the principal products produced at our Tulsa Refinery:
Year Ended
December 31,
2009
Tulsa Refinery
Sales of produced refined products:
Gasolines26%
Diesel fuels29%
Jet fuels10%
Lubricants16%
Gas oil / intermediates17%
LPG and other2%
Total100%

-19-

Light products are shipped by product pipelines and are also made available to customers through truck and rail loading facilities. The Tulsa Refinery’s principal customers for conventional gasoline include Sinclair, other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, because of regulatory requirements, depending on the area in which gasoline is to be sold. Sinclair and railroads are the primary diesel customers. Jet fuel is sold primarily for commercial use. LPGs are sold to LPG wholesalers and retailers.
The specialty lubricant products produced at the Tulsa Refinery are high value products that provide a disproportionately high margin contribution to the refinery. Specialty lubricant products are sold in both commercial and specialty markets. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural oils, primarily formulated as supplemental carriers for herbicides, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the adhesive or candle-making businesses.
Asphalt and roofing flux are sold primarily to paving contractors and manufacturers of roofing products.
Crude Oil and Feedstock Supplies
The Tulsa Refinery is located approximately 50 miles from Cushing, Oklahoma, a significant crude oil pipeline crossroad and storage hub. Local pipelines provide access to regional crude production as well as many United States onshore, Gulf of Mexico, Canadian and other foreign crudes. The proximity of the refinery to this pipeline and storage hub provides the refinery with the flexibility to optimize its crude slate and maintain lower crude inventories than a typical refinery.
The refinery also purchases other feedstocks on an opportunistic basis. From time to time, the refinery purchases naphtha, gasoline components, transmix, light cycle oil, lube blend stocks or residuals from other refineries. These feedstocks are delivered by truck, rail car or pipeline, depending on product and logistical requirements.
Capital Improvement Projects
Our total approved capital budget for the Tulsa Refinery for 2010 is $101.6 million. Additionally, capital costs of $24 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $63.2 million in capital costs in 2010, including capital projects approved in prior years. The following summarizes our key capital projects.
We are proceeding with the integration project of our Tulsa Refinery west and east facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD. The integration project involves the installation of interconnect pipelines that will permit us to transfer various intermediate streams between the two facilities. We have also signed a 10-year agreement with a third party for the use of an additional line for the transfer of gasoline blend stocks which is currently in service. These interconnect lines will allow us to eliminate the sale of gas oil at a discount to WTI under our 5-year gas oil off take agreement with a third party, optimize gasoline blending, increase our utilization of better process technology, and reduce operating costs. Also, as part of the integration, we are planning to expand the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD, eliminating the need to construct a new LSG specificationsdiesel hydrotreater at our west facility as requiredpreviously planned. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We are currently planning to complete the integration projects by the EPA.
To fully take advantageend of the economics on the Woods Cross expansion project, additional crude pipeline capacity2010.
The combined Tulsa Refinery facilities also will be required to move Canadian crudecomply with MSAT2 regulations in order to meet new benzene reduction requirements for gasoline. We have elected to largely use existing equipment at the Woods Cross Refinery. HEP’s joint venture pipelineTulsa Refinery east facility to split reformate from reformers at both west and east facilities and install a new benzene saturation unit to achieve the required benzene reduction at an estimated cost of approximately $15 million. Our Tulsa Refinery is required to meet MSAT2 1.3% benzene levels in gasoline beginning in July 2012 and we expect complete this project well before then. We will be required to buy credits until this project is complete, as required by law, beginning in 2011.

-20-

Our consent decree with Plainsthe EPA requires recovery of sulfur from the refinery fuel gas system at the Tulsa Refinery west facility by the end of 2013. We estimate our investment to comply with the requirements will permitbe approximately $20 million. The consent decree also requires shutdown, replacement, or installation of low NOx burners in three low pressure boilers by the transportationend of additional crude oil into2013. We are still evaluating the Salt Lake City area. HEP’s joint venture project with Plains is further described underbest solution to this issue.
We believe that the HEP sectionsynergy of this discussionthe Tulsa Refinery west and east facilities operated as a single integrated facility will result in savings of businessapproximately $110 million of expected capital expenditures related to ULSD compliance. Also as a result of the integrated facility, we expect to be able to reduce capital expenditures for the forthcoming benzene in gasoline requirements from approximately $30 million for the Tulsa Refinery west facility alone to approximately $15 million for the integrated complex. Even if we are able to realize the operating synergies of the integrated facility, our Tulsa Refinery will still require sulfur recovery investment, but we estimate combining the two refineries will reduce our net near-term capital expenditure requirements by approximately $125 million, excluding the cost to construct the pipelines that will integrate the west and properties.east facilities.
In December 2007, we entered intoUNEV Pipeline
Under a definitive agreement with Sinclair, towe are jointly buildbuilding the UNEV Pipeline, 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 northNorth Las Vegas areas (the “UNEV Pipeline”).areas. Under the agreement, we own a 75% interest in the joint venture pipeline andwith Sinclair, ownsour joint venture partner, owning the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd,BPD, with the capacity for further expansion to 120,000 bpd.BPD. The total cost of the pipeline project including terminals is expected to be $300.0$275 million, with our share of the cost totaling $225.0$206 million. We expect to spend approximately $80 million in capital costs in 2010, with our share of the cost totaling $60 million.
In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per dayBPD 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 dayBPD in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered intoWe have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture

-16-

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
We currently anticipate that will serve as a key component of our UNEV joint venture pipeline.
The UNEV project is inall regulatory approvals required to commence the final stageconstruction of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceedUNEV Pipeline will now be received duringby the end of the second quarter of 2009, we2010. Once such approvals are currently evaluating whether to maintainreceived, construction of the current completionpipeline will take approximately nine months. Under this schedule, for UNEVthe pipeline would become operational during the first quarter of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.2011.
Holly Energy Partners,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.Oklahoma.
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, Oklahoma, 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.

-21-

2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, HEP acquired certain logistics and storage assets from an affiliate of Sinclair for $79.2 million consisting of storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at Sinclair’s refinery located in Tulsa, Oklahoma. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million. Concurrent with this transaction we entered into a 15-year pipeline, tankage and loading rack throughput agreement with HEP (the “HEP PTTA”), whereby we agreed to transport, throughput and load volumes of product via HEP’s Tulsa logistics and storage assets that will initially result in minimum annual payments to HEP of $13.8 million.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma (the “Centurion Pipeline”) and a 37-mile, 8-inch crude oil pipeline that connects HEP’s New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).
The Roadrunner Pipeline provides our Navajo Refinery with direct access to a wide variety of crude oils available at Cushing, Oklahoma. In connection with this transaction, we entered into a 15-year pipeline agreement with HEP, (the “HEP RPA”), whereby we agreed to transport volumes of crude oil on HEP’s Roadrunner Pipeline that will initially result in minimum annual payments to HEP of $9.2 million.
The Beeson Pipeline operates as a component of HEP’s crude pipeline system and provides us with added flexibility to move crude oil from HEP’s crude oil gathering system to our Navajo Refinery Lovington facility for processing.
Tulsa Loading Racks Transaction
On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa Refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa Refinery onto rail cars and/or tanker trucks.
In connection with this transaction, we entered into a 15-year equipment and throughput agreement with HEP, (the “HEP ETA”), whereby we agreed to throughput a minimum volume of products via HEP’s Tulsa loading racks that will initially result in minimum annual payments to HEP of $2.7 million.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million. The pipeline runs 65 miles from our Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery located in Artesia, New Mexico. This pipeline was placed in service effective June 1, 2009 and operates as a component of HEP’s intermediate pipeline system that services our Navajo Refinery.
In connection with this transaction, we agreed to amend our intermediate pipeline agreement with HEP (the “HEP IPA”). As a result, the term of the HEP IPA was extended by an additional four years and now expires in June 2024. Additionally, our minimum commitment under the HEP IPA was increased and currently results in minimum annual payments to HEP of $20.7 million.
SLC Pipeline Joint Venture Interest
On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. The SLC Pipeline commenced operations effective March 2009 and allows various refineries 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 flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. HEP’s capitalized joint venture contribution was $25.5 million.
Rio Grande Pipeline Sale
On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the results of operations of Rio Grande and gain of $14.5 million on the sale are presented in discontinued operations.

-22-

Transportation Agreements
Agreements with HEP
HEP serves our refineries in New Mexico, Utah and UtahOklahoma under several long-term pipeline and terminal, tankage and throughput agreements.
In connection with our 2009 asset transfers to HEP, as described above, we entered into three new 15-year transportation agreements with HEP, each expiring in 2024.
In addition, we have a 15-yeartransportation agreement with HEP that relates to the pipelines and terminals agreementthat we contributed to HEP at the time of its initial public offering in 2004 that expires in 2019 (the “HEP PTA”) expiring, the HEP IPA that relates to the intermediate pipelines sold to HEP in 20192005 and in June 2009 that expires in 2024 and a 15-year intermediate pipelinetransportation agreement expiringthat relates to the Crude Pipelines and Tankage Assets sold to HEP in 20202008 that expires in 2023 (the “HEP IPA”CPTA”).
Under these agreements, we pay HEP fees to transport, store and storethroughput volumes of refined product and crude oil on HEP’s pipelinespipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change equal tobased upon the change in the producer price indexProducer 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 tobased upon the percentage change in PPI or Federal Energy Regulatory Commission (“FERC”) index, but not belowwith the initial tariff rate. Following the July 1, 2008 PPI rate adjustment, minimum payments under the HEP PTA andexception of 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, butgenerally 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.PPI or FERC index. The FERC Oil Pipeline Indexindex is the change in the PPI plus a FERC adjustment factor. factor that is reviewed periodically. Following the July 1, 2009 PPI rate adjustments, these agreements, including our new 2009 agreements with HEP, will result in minimum payments to HEP of $118.5 million for the twelve months ending June 30, 2010.
Additionally, in February 2010, we amendedentered into a pipeline systems operating agreement with HEP expiring in 2014 (the “HEP Pipeline Operating Agreement”). Under the Omnibus HEP Pipeline Operating Agreement, effective December 1, 2009, HEP will operate certain of our tankage, pipelines, asphalt racks and terminal buildings for an annual management fee of $1.3 million.
We reconsolidated HEP effective March 1, 2008. Following our reconsolidation, our transactions with HEP including fees that we pay under our HEP transportation agreements are eliminated and have no impact on our consolidated financial statements since HEP is a consolidated subsidiary.
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.Alon
HEP also has a 15-year pipelines and terminals agreement with Alon expiring in 2020 (the “Alon PTA”), under which Alon has agreed to transport on HEP’s pipelines and throughput through theirits terminals, volumes of refined products that results in a minimum level of annual revenue. Under the Alon PTA, theThe agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but will not decrease below the initial tariff rate.$20.2 million annual amount. Following the March 1, 2009 PPI adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2010 is $21.7 million. Furthermore, for the twelve months ending February 28, 2011, Alon’s minimum commitment will increase to $22.7 million as a result of the upcoming March 1, 2010 PPI adjustment.

-17-

-23-

As of December 31, 2008,2009, 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    
       
         
  Minimum Annualized     
Agreement Commitment
(In millions)		  Year of
Maturity		 Contract Type
         
HEP PTA(1)
 $43.7  2019 Minimum revenue commitment
HEP IPA(1)(2)
  20.7  2024 Minimum revenue commitment
HEP CPTA(1)(3)
  28.4  2023 Minimum revenue commitment
HEP PTTA(1)
  13.8  2024 Minimum revenue commitment
HEP RPA(1)
  9.2  2024 Minimum revenue commitment
HEP ETA(1)
  2.7  2024 Minimum revenue commitment
Alon PTA(4)
  21.7  2020 Minimum volume commitment
Alon capacity lease(4)
  6.4  Various Capacity lease
        
         
Total $146.6     
        
(1) HEP’s revenue under the HEP PTA, HEP IPA and HEP CPTAthese transportation agreements with us represents intercompany revenue and is eliminated in our consolidated financial statements.
 
(2) Reflects amended terms of the Holly IPA effective June 2009.
(3)Reflects amended terms of the Holly CPTA effective January 2009.
(4)Minimum annual revenues attributable to long-term service contracts with unaffiliated parties is $28.8are $28.1 million.
As of December 31, 2008,2009, 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.
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;
three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico;
approximately 960 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery;
approximately 10 miles of crude oil and refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah; and
gasoline and diesel connecting pipelines that support our Tulsa Refinery east facility.
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.
four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,000,000 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;
a refined product truck loading rack facility at each of our Navajo and Woods Cross Refineries, refined product and lube oil rail loading racks and a lube oil truck loading rack at our Tulsa Refinery west facility and a refined product, asphalt and LPG truck loading rack at our Tulsa Refinery east facility;
a Roswell, New Mexico jet fuel terminal leased through September 2011;
on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries having an aggregate storage capacity of approximately 600,000 barrels; and
on-site refined product tankage at our Tulsa Refinery having an aggregate storage capacity of approximately 1,400,000 barrels.

-18-

-24-

HEP also owns a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City area.
Capital Improvement Projects
HEP’s capital budget for 20092010 is comprised of $3.7$4.8 million for maintenance capital expenditures and $2.2$6 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, expiresexpiring in 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, 2008,2009, we had 9781,632 employees, of which 339347 are currently covered by collective bargaining agreements. We consider our employee relations to be good. We successfully renegotiatedare currently negotiating the collective bargaining agreement for certain of our Utah refinery and extended the term to 2012Navajo Refinery Lovington facility employees, which agreement expires in February, 2009 (subject only to ongoing efforts to document the interim letter agreement with formal contract terms) and theApril 2010. We also have a collective bargaining agreement for certain of our New Mexico refineryWoods Cross Refinery employees that expires in 2010.2012.

-19-

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, inIn 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 ofOur Navajo and Woods Cross Refineries as well as our refineries metTulsa Refinery east facility meet the ultimate 15 PPM standard for both our non-road and highway diesel. Currently, our Tulsa Refinery west facility does not meet these regulations. Under our Tulsa Refinery integration project, we will be expanding our Tulsa Refinery east facility’s diesel hydrotreater unit, enabling it to process all diesel fuel by June 1, 2006. Althoughproduced at 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,Tulsa Refinery.

-25-

Additionally, we will be required to meet another EPA regulation limiting the average concentration of sulfur in gasoline to 30 PPM.PPM by January 1, 2011. Our currentTulsa Refinery east facility meets this new LSG standard. Products produced at our Tulsa Refinery west facility will also meet this standard, once the interconnecting lines that connect the two Tulsa facilities are in service. Additionally, we are proceeding with capital projects include plant modificationsat our Navajo and enhancements that will enable usWoods Cross Refineries in order to meet this new LSG requirement.
We are currently making plans to comply with the EPA’s new EPAMSAT2 regulations on gasoline that will impose further reductions in the benzene content of our produced gasoline and wouldbeginning January 1, 2011. In addition , the renewable fuel standards will mandate the blending of prescribed substantial percentages of renewable fuels (e.g. ethanol)ethanol and biofuels) 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.

-20-

We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several 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. TheThese 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, 20082009 we had an accrual of $7.3$30.4 million related to such environmental liabilities of which $4.2$24.2 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.

-26-

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.

-21-

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

-27-

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.

-22-

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.

-28-

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.

-23-

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.

-29-

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.

-24-

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 emissions of greenhouse gas emissionsgases, or “GHGs,” (including carbon dioxide, methane and nitrous oxides). Also, new federal or state legislation or regulatory programs that restrict emissions of greenhouse gasesGHGs 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“Legal Proceedings.”

-30-

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the refined products we produce.
On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of GHGs from motor vehicles and that could also lead to the imposition of GHG emission limitations in CAA permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the refined products that we produce.
Also, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” (“ACESA”), also known as the “Waxman-Markey cap-and-trade legislation.” The purpose of ACESA is to control and reduce emissions of GHGs in the United States. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances permitted by ACESA declines each year, the cost or value of allowances would be expected to escalate significantly. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and gas. The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.
It is not possible at this time to predict whether climate change legislation will be enacted, but any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for refined products we produce.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations
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.

-25-

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.

-31-

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 be unsuccessful in integrating the operations of the assets we have recently acquired or of any future acquisitions with our operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. For example, in 2009, we completed the acquisition of two refineries in Tulsa, Oklahoma. We will face certain challenges as we continue to integrate the operations of the Tulsa facilities into our business. In particular, the acquisition of the Tulsa facilities has significantly expanded our geographic scope, the types of business in which we are engaged, the number of our employees and the number of refineries we operate, thereby presenting us with significant challenges as we work to manage the substantial increases in scale resulting from the acquisition. We must integrate a large number of systems, both operational and administrative. Delays in this process could have a material adverse effect on our revenues, expenses, operating results and financial condition. In addition, events outside of our control, including changes in state and federal regulations and laws and/or delays or failure to obtain environmental permits needed for integrating projects, could adversely affect our ability to realize the anticipated benefits from the acquisition of the Tulsa facilities. We can give no assurance that our acquisition of the Tulsa facilities will perform in accordance with our expectations. We can give no assurance that our expectations with regards to integration and synergies will materialize. Our failure to successfully integrate and operate the Tulsa facilities and to realize the anticipated benefits of the acquisition, could adversely affect our operating, performing and financial results.
Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of the acquisitions we recently completed or as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, including the assets and businesses we acquired in 2009. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing sales agreementscontracts with our customers at rates sufficient to maintain current revenues and cash flows 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.

-32-

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 disruption or proration of the refined product distribution systems we utilize could negatively impact our profitability.
We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by Navajo, Woods Cross, and Tulsa are SFPP and Plains, Chevron, and Magellan, respectively. All three refineries also utilize systems owned by HEP. If these key pipelines or their associated tanks and terminals become inoperative or decrease the capacity available to us, we may not be able to sell our product or we may be required to hold our product in inventory or supply products to our customers through an alternative pipeline or by rail or additional tanker trucks from the refinery all of which could increase our costs and result in a decline in profitability.
The potential operation of new or expanded 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.markets.
If one ofOther refined product transportation pipelines currently supply our existing markets or could potentially supply our existing markets in the majorfuture.
The refined productsproduct transportation pipelines becomes inoperative, we would be required to keep refined products in inventory orthat also supply refined products to our customers through an alternative pipeline orthe markets supplied by additional tanker trucks from the refinery, which could increase our costsNavajo Refinery include Longhorn, Kinder Morgan, Plains, HEP, and result in a decline in profitability.NuStar Energy. The Longhorn Pipeline is an approximately 72,000 BPDa common carrier pipeline that deliverssupplies the El Paso market with refined products utilizing a direct route from refineries as distant as the Texas Gulf CoastCoast. The Longhorn Pipeline is a converted crude oil pipeline with an approximate capacity of 72,000 BPD of refined products. Magellan purchased the Longhorn Pipeline out of bankruptcy in 2009. Flying J formerly owned the Longhorn Pipeline prior to its bankruptcy in 2008. In addition to supplying Arizona markets from El Paso, Kinder Morgan also supplies Arizona markets from the West Coast. The Plains pipeline currently supplies New Mexico markets from El Paso. In addition, NuStar Energy LP and HEP own pipelines into the El Paso and through interconnectionsNew Mexico markets.
The refined product transportation pipelines that also supply the markets supplied by the Woods Cross Refinery include Chevron, Pioneer, and Yellowstone Pipelines. The Chevron system transports products from Salt Lake City to Idaho and eastern Washington. The Pioneer Pipeline transports products from Wyoming and Montana refineries into Salt Lake City. The Yellowstone Pipeline transports products from Montana refineries into eastern Washington.
The refined product transportation pipelines that also supply the markets supplied by the Tulsa Refinery include Magellan, Explorer, and Kaneb Pipelines. The Explorer Pipeline transports refined products from Gulf Coast refineries to Tulsa where it interconnects with third-party common carrier pipelines, intoMagellan prior to proceeding to the Chicago area. The Kaneb Pipeline transports refined products from northern Texas, Oklahoma, and Kansas refineries to markets in Kansas, Nebraska, Iowa, North Dakota, and South Dakota. These markets are in close proximity to markets supplied by the Magellan system.

-26-

-33-

Arizona market. Longhorn Pipeline isThe expansion of any of these pipelines, the conversion of existing pipelines into refined products, or the construction of 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 Phoenixnew 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 ofinto our markets iscould negatively impact the presence of pipeline capacity from the West Coast into our Arizona markets. Additional increases in shipmentssupply 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.”our profitability.
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% 34%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, Utah and UtahOklahoma under three 15-year pipelinesseveral long-term pipeline and terminalsterminal, tankage and tankagethroughput agreements expiring in 2019 through 2023.2024. 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.

-27-

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 exceeds45days. 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.

-34-

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. Further, our underwriters could have credit issues that affect their ability to pay claims. 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.

-28-

As of December 31, 2008,2009, approximately 35%21% of our employees were represented by labor unions under collective bargaining agreements expiringwith various expiration dates. Effective February 1, 2009, a new agreement was reached with the United Steelworkers which applies to approximately 7% of our employees, which agreement will now expire on January 31, 2012. As of December 31, 2009, approximately 14% of our employees were represented by labor unions under a collective bargaining agreement that expires 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.

-35-

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. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt.
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.
We may be unable to pay future dividends.
We will only be able to pay dividends from our available cash on hand, cash from operations or borrowings under our credit agreement. The declaration of future dividends on our common stock will be at the discretion of our board of directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital requirements, restrictions in our debt agreements and legal requirements. We cannot assure you that any dividends will be paid or the frequency of such payments.
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.

-29-

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.

-36-

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 fulldesired capacity. Our failure to operate our refineries at fulldesired 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 fulldesired 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.us or require credit enhancement. 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 or credit enhancement requirements 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 fulldesired capacity. A failure to operate our refineries at fulldesired capacity could adversely affect our profitability and cash flow.
We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
Although the domestic capital markets have shown signs of improvement in recent months, global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, increased unemployment, geopolitical issues and the current weak economic conditions. In addition, the fixed-income markets have experienced periods of extreme volatility that have negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

-30-

-37-

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
As of December 31, 2009, the principal amount of our total outstanding debt was $300 million.
Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.
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.terms. 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$10 million to $20.0$20 million to the retirement plan in 2009.2010. 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.

-38-

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, 2008,2009, 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.
The new and revamped equipment in our facilities may not perform according to expectations which may cause unexpected maintenance and downtime and could have a negative effect on our future results of operations and financial condition.
We are completing major capital investment programs at both our Navajo and Woods Cross Refineries. At the Tulsa Refinery we have various projects planned to integrate the two facilities to fully utilize their capabilities. All three refineries also have various environmental compliance related projects.
The installation of new equipment and the revamp of key existing equipment involve significant risks and uncertainties, including the following:
Equipment may not perform at expected throughput levels,
Actual yields or product quality may differ from design,
Actual operating costs may be higher than expected,
Equipment may need to be redesigned, revamped, or replaced for the new units to perform as expected
Item 1B.
Item 1B. Unresolved Staff Comments
We do not have any unresolved staff comments.
Item 3.
Item 3. Legal Proceedings
Commitment and Contingency Reserves
When deemed necessary, we establish reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

-39-

SFPP Litigation
a. The Early Complaint Cases
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.SFPP, L.P. 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.Arizona on SFPP’s East Line. The Court of Appeals

-31-

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.
b.Settlements
We and other shippers have been engaged in settlement discussions with SFPP on remaining issues relating to East Line service 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 CommissionFERC approved the settlement on January 29, 2009. The settlement will reducereduced SFPP’s current rates and requirerequired SFPP to make additional payments to us of approximately $2.0 million.$2.9 million, which was received on May 18, 2009.
c.The Latest Rate Proceeding
On June 2, 2009, SFPP notified us that it would terminate the October 2008 settlement, as provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial rate increases for East Line service to become effective September 1, 2009. We and several other shippers filed protests at the FERC challenging the rate increase and asking the FERC to suspend the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending the effective date of the rate increase until January 1, 2010, on which date the rate increase was placed into effect, and setting the rate increase for a full evidentiary hearing to be held in 2010. We are not in a position to predict the ultimate outcome of the rate proceeding.
MTBE Litigation
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 iswas 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 priorPursuant to the date of this report,an agreement dated December 30, 2009, 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 amountsreleased with respect to the claims asserted against it in this matter.lawsuit, and the lawsuit against it has been dismissed with prejudice.

-40-

NMED NOV
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

-32-

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.
Woods Cross Construction Dispute 1
Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries arewere named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in state district courtthe 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 lienThis matter has also been filed in the county records against the Refinery property in that amount. Our subsidiaries have tendered defenseresolved through mutual agreement of the complaint toparties. All actions have been settled for an immaterial amount and dismissed with prejudice by 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.court.
Woods Cross Construction Dispute 2
Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries arewere named, along with other parties, as defendants in a lawsuit filed in December 2008on April 22, 2009 by Brahma Group, Inc. in the U.S.State District Court for the Central District ofin Davis County, 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, andConstructors. Our subsidiaries have filed an answer toanswered the complaint denyingand denied any liability. We intendThe plaintiff and the general contractor have agreed to vigorously defend againstarbitrate their dispute, and the claims asserted inagainst our subsidiaries have been stayed pending the lawsuit.outcome of that arbitration. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
Cut Bank Hill Environmental Claims
Prior to the sale by Holly Corporation of the Montana Refining Company (“MRC”) 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 RefiningMRC and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against Montana RefiningMRC 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 (“MDEQ”) directing Montana RefiningMRC and other companies to complete a remedial investigation and a request by the MDEQ that Montana RefiningMRC and other companies pay $147,500approximately $150,000 to reimburse the State’s costs for remedial actions. Montana Refining CompanyMRC has denied responsibility for the requested EPA and the 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

-33-

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.OSHA Inspection — Woods Cross
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.was issued. Our answer is duewas filed and served on March 4th4, 2009 and discovery will continue until Julyended on January 6, 2009. No2010. The hearing date has been set.set for July 6, 2010. We intend to vigorously defend this citation and believe that we have strong defenses on the merits.

-41-

OSHA Inspection — Tulsa Refinery east facility
In June 2007, OSHA announced a NEP for inspecting approximately 80 refineries within its jurisdiction. As part of the NEP, OSHA conducted an inspection of Sinclair Tulsa Refining Company’s (“Sinclair Tulsa”) refinery in Tulsa, Oklahoma (our Tulsa Refinery east facility) from February 4, 2009 through August 3, 2009. On August 4, 2009, OSHA issued two citations to Sinclair Tulsa, alleging 51 serious violations and 1 willful violation of various safety standards including the Process Safety Management Standard (“PSM”) and the General Duty Clause. OSHA proposed penalties totaling $240,750. Sinclair filed a notice of contest, challenging the citations. Because the proposed penalties exceed $100,000, the matter was referred for mandatory settlement before the Occupational Safety and Health Review Commission. The settlement conference is scheduled to take place March 16 — 17, 2010 in Dallas, Texas.
Our subsidiary, Holly Refining & Marketing — Tulsa LLC (“HRM-Tulsa”), entered into an Asset Sale & Purchase Agreement (the “Agreement”) with Sinclair Tulsa dated October 19, 2009 to acquire the Tulsa Refinery east facility, and the sale closed on December 1, 2009. HRM-Tulsa intervened in the case against Sinclair Tulsa pending before the Occupational Safety and Health Review Commission shortly after the sale closed. Under the terms of the Agreement, Sinclair retains responsibility for defending the OSHA citations and paying any penalties, and HRM-Tulsa has the discretion to select the means and methods of improving the PSM program. HRM-Tulsa is in the initial stages of evaluating the feasibility and range of options to make such PSM program improvements at the Tulsa Refinery east facility.
Discharge Permit Appeal — Tulsa Refinery west facility
Our subsidiary, HRM-Tulsa is party to parallel Oklahoma administrative and state district court proceedings involving a challenge, originally filed by Sunoco, Inc. (R&M), to the terms of the Oklahoma Department of Environmental Quality (“ODEQ”) permit that governs the discharge of industrial wastewater from what is now our Tulsa Refinery west facility. After our acquisition of the Tulsa Refinery west facility, we were substituted for Sunoco in both proceedings. On February 1, 2010, we entered into a settlement agreement with the Oklahoma Department of Environmental Quality. The agreement provided, among other things, for the amendment of the permit to require that the Tulsa Refinery west facility make certain modifications in its system for handling storm flows. These modifications are required to be complete within three years of the issuance of the revised permit. Both the administrative and the state district court proceedings have been stayed to permit this settlement agreement to be effectuated. Once the agreed-upon changes become effective, both proceedings will be dismissed. Preliminary engineering is underway to develop a final scope and capital estimate, and any process modification is subject to regulatory review and approval. Accordingly, it is not possible to estimate the costs of compliance with the new permit provision at this time.
Unclaimed Property Audit
A multi-state audit of our unclaimed property compliance and reporting is being conducted by Kelmar Associates, LLC on behalf of twelve states. We expect this audit process to take several years to be resolved due to the lengthy period covered by the audit (1981 — 2004). It is not yet possible to accurately estimate the amount, if any, that is owed to each of the states since only preliminary investigation has occurred to date.
Other
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.
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 2008.2009.

-34-

-42-

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 
                 
              Trading 
Years Ended December 31, High  Low  Dividends  Volume 
                 
2009
                
Fourth quarter $33.53  $23.57  $0.15   52,039,700 
Third quarter $26.22  $16.71  $0.15   50,535,600 
Second quarter $31.63  $17.23  $0.15   73,542,100 
First quarter $27.42  $18.15  $0.15   85,489,800 
                 
2008
                
Fourth quarter $28.83  $10.84  $0.15   81,694,000 
Third quarter $37.47  $25.88  $0.15   88,195,700 
Second quarter $49.62  $36.13  $0.15   79,585,500 
First quarter $56.81  $38.84  $0.15   79,892,000 
As of February 6, 2009,8, 2010, we had approximately 21,50023,200 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 Agreementcredit agreement limits the payment of dividends. See Note 1112 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 2008.2009.

-35-

-43-

Item 6.
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 Annual Report on 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 
                     
  Years Ended December 31, 
  2009(1)(4)  2008(1)(4)  2007(1)(4)  2006(1)(3)(4)  2005(1)(2)(3)(4) 
  (In thousands, except per share data) 
FINANCIAL DATA
                    
For the period
                    
Sales and other revenues $4,834,268  $5,860,357  $4,791,742  $4,023,217  $3,046,313 
Income from continuing operations before income taxes  43,803   187,746   499,444   383,501   270,373 
Income tax provision  7,460   64,028   165,316   136,603   99,626 
                
Income from continuing operations  36,343   123,718   334,128   246,898   170,747 
Income from discontinued operations, net of taxes  16,926   2,918   —   19,668   2,963 
                
Net income before cumulative effect of change in accounting principle  53,269   126,636   334,128   266,566   173,710 
Cumulative effect of accounting change (net of income tax expense of $426)  —   —   —   —   669 
                
Net income(5)
  53,269   126,636   334,128   266,566   174,379 
Less net income attributable to noncontrolling interest(5)
  33,736   6,078   —   —   6,721 
                
                     
Net income attributable to Holly Corporation Stockholders(5)
 $19,533  $120,558  $334,128  $266,566  $167,658 
                
                     
Earnings per share attributable to Holly Corporation stockholders — basic $0.39  $2.40  $6.09  $4.68  $2.72 
                     
Earnings per share attributable to Holly Corporation stockholders — diluted $0.39  $2.38  $5.98  $4.58  $2.65 
                     
Cash dividends declared per common share $0.60  $0.60  $0.46  $0.29  $0.19 
                     
Average number of common shares outstanding:                    
Basic  50,418   50,202   54,852   56,976   61,728 
Diluted  50,595   50,549   55,850   58,210   63,244 
                     
Net cash provided by operating activities $214,058  $155,490 155,490  $422,737  $245,183  $251,234 
Net cash provided by (used for) investing activities $(537,116) $(57,777) $(293,057) $35,805  $(320,135)
Net cash provided by (used for) financing activities $406,849  $(151,277) $(189,428) $(175,935) $50,505 
                     
At end of period
                    
Cash, cash equivalents and investments in marketable securities $125,819  $94,447  $329,784  $255,953  $254,842 
Working capital(6)
 $257,899  $68,465  $216,541  $240,181  $210,103 
Total assets $3,145,939  $1,874,225  $1,663,945  $1,237,869  $1,142,900 
Total debt, including short-term $667,649  $370,914  $—  $—  $— 
Total equity(5)
 $1,207,871  $936,332  $593,794  $466,094  $377,351 
(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.refinery. Results of operations of the Montana Refineryrefinery that were previously reported in operations are now reportedpresented in discontinued operations.
(4)On December 1, 2009, HEP sold its 70% interest in Rio Grande. Accordingly, results of operations of Rio Grande that were previously reported in operations are presented in discontinued operations.
(5)Accounting standards became effective January 1, 2009 that change the classification of noncontrolling interests, also referred to as minority interests, in the Consolidated Financial Statements. As a result, all previous references to “minority interest” within these financial statements have been replaced “noncontrolling interest.” Also, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of these standards, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in the Consolidated Financial Statements. We have adopted these standards on a retrospective basis. While this presentation differs from previous requirements under GAAP, it did not affect our net income and equity attributable to Holly Corporation stockholders.
(6)At December 31, 2008, HEP classified $29 million in credit agreement borrowings as short-term debt.

-36-

-44-

Item 7.
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.person with certain exceptions. For periods afterprior to our reconsolidation of HEP effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally includeexclude HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions.Corporation. 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 twothree refineries in Artesia and Lovington, New Mexico (operated as one refinery) and, Woods Cross, Utah.Utah and Tulsa, Oklahoma. As of December 31, 2008,2009, our refineries had a combined crude capacity of 116,000256,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2008,2009, we also owned a 46%34% interest in HEP, a consolidated subsidiary, which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande.assets.
Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel, and jet fuel, specialty lubricant products, and specialty and modified asphalt in markets in the southwesternSouthwestern, Rocky Mountain and westernMid-Continent regions of the United States. Our sales and other revenues and net income attributable to Holly Corporation stockholders for the year ended December 31, 20082009 were $5,867.7$4,834.3 million and $120.6$19.5 million, respectively. Our sales and other revenues and net income attributable to Holly Corporation stockholders for the year ended December 31, 20072008 were $4,791.7$5,860.4 million and $334.1$120.6 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the year ended December 31, 20082009 were $5,667.3$4,754 million, an increasea decrease from $4,325.4$5,664.7 million for the year ended December 31, 2007.2008.
On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to Plains a portion of the crude oil petroleum storage tanks and certain refining-related crude oil receiving pipeline facilities, that were acquired as part of the refinery assets for $40 million.
On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BPSD refinery from Sinclair also located in Tulsa, Oklahoma for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we will reimburse Sinclair approximately $8 million upon their satisfactory completion of certain environmental projects at the refinery. The refinery also produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.
Seperately, HEP, also a party to the December 1, 2009 transaction with Sinclair, acquired certain logistics and storage assets located at our Tulsa Refinery east facility. See “Holly Energy Partners, L.P. — 2009 Acquisitions” under Items 1 and 2, “Business and Properties” for additional information on this transaction as well as HEP’s other 2009 asset acquisitions from us.
Also on December 1, 2009, HEP sold its 70% interest in Rio Grande to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.

-45-

On February 29, 2008, we closed on the sale ofsold the Crude Pipelines and Tankage Assets to HEP for $180.0$180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refineryrefinery 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 Refineryboth of our refinery complexes, a jet fuel products pipeline and leased terminal 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 crudeand product pipelines and tankage facilities that at the agreed rates, resultsupport our refinery 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.
Woods Cross, Utah. HEP is a VIE as defined under FIN No. 46R.GAAP. Under the provisions of FIN No. 46R,GAAP, 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 for2008. Therefore, intercompany transactions with HEP are eliminated in 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.

-37-

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.consolidated financial statements.
RESULTS OF OPERATIONS
Financial Data
            
             Years Ended December 31, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (In thousands, except per share data) 
 (In thousands, except per share data)  
Sales and other revenues $5,867,668 $4,791,742 $4,023,217  $4,834,268 $5,860,357 $4,791,742 
Operating costs and expenses:  
Cost of products sold (exclusive of depreciation and amortization) 5,280,699 4,003,488 3,349,404  4,238,008 5,280,699 4,003,488 
Operating expenses (exclusive of depreciation and amortization) 267,570 209,281 208,460  356,855 265,705 209,281 
General and administrative expenses (exclusive of depreciation and amortization) 54,906 68,773 63,255  60,343 55,278 69,185 
Depreciation and amortization 63,789 43,456 39,721  98,751 62,995 43,456 
Exploration expenses, including dry holes 372 412 486 
              
Total operating costs and expenses 5,667,336 4,325,410 3,661,326  4,753,957 5,664,677 4,325,410 
              
 
Income from operations 200,332 466,332 361,891  80,311 195,680 466,332 
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 — — 
Equity in earnings of SLC Pipeline 1,919 — — 
Interest income 10,824 15,089 9,757  5,045 10,797 15,089 
Interest expense  (23,955)  (1,086)  (1,076)  (40,346)  (23,955)  (1,086)
Acquisition costs — Tulsa Refineries  (3,126) — — 
Impairment of equity securities —  (3,724) — 
Gain on sale of Holly Petroleum, Inc. — 5,958 — 
Equity in earnings of HEP — 2,990 19,109 
              
  (14,948) 33,112 21,610   (36,508)  (7,934) 33,112 
              
Income from continuing operations before income taxes 185,384 499,444 383,501  43,803 187,746 499,444 
Income tax provision 64,826 165,316 136,603  7,460 64,028 165,316 
              
Income from continuing operations 120,558 334,128 246,898  36,343 123,718 334,128 
Income from discontinued operations, net of taxes — — 19,668 
Income from discontinued operations, net of taxes(1)
 16,926 2,918 — 
       
Net income(2)
 53,269 126,636 334,128 
Less noncontrolling interest in net income(2)
 33,736 6,078 — 
       
Net income attributable to Holly Corporation stockholders(2)
 $19,533 $120,558 $334,128 
       
 
Earnings attributable to Holly Corporation stockholders: 
Income from continuing operations $15,209 $119,206 $334,128 
Income from discontinued operations 4,324 1,352 — 
              
Net income $120,558 $334,128 $266,566  $19,533 $120,558 $334,128 
              
  
Basic earnings per share: 
Earnings per share attributable to Holly Corporation stockholders — basic: 
Continuing operations $2.40 $6.09 $4.33  $0.30 $2.37 $6.09 
Discontinued operations — — 0.35  0.09 0.03 — 
              
Net income $2.40 $6.09 $4.68  $0.39 $2.40 $6.09 
              
  
Diluted earnings per share: 
Earnings per share attributable to Holly Corporation stockholders — diluted: 
Continuing operations $2.38 $5.98 $4.24  $0.30 $2.36 $5.98 
Discontinued operations — — 0.34  0.09 0.02 — 
              
Net income $2.38 $5.98 $4.58  $0.39 $2.38 $5.98 
              
  
Cash dividends declared per common share $0.60 $0.46 $0.29  $0.60 $0.60 $0.46 
              
  
Average number of common shares outstanding:  
Basic 50,202 54,852 56,976  50,418 50,202 54,852 
Diluted 50,549 55,850 58,210  50,603 50,549 55,850 

-38-

-46-

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 
         
  Years Ended December 31, 
  2009  2008 
  (In thousands) 
         
Cash, cash equivalents and investments in marketable securities $125,819  $94,447 
Working capital(3)
 $257,899  $68,465 
Total assets $3,145,939  $1,874,225 
Long-term debt — Holly Corporation $328,260  $— 
Long-term debt — Holly Energy Partners $379,198  $341,914 
Total equity(2)
 $1,207,871  $936,332 
(1)On December 1, 2009, HEP sold its 70% interest in Rio Grande. Accordingly, results of operations of Rio Grande are presented in discontinued operations.
(2)Accounting standards became effective January 1, 2009 that change the classification of noncontrolling interests, also referred to as minority interests, in the Consolidated Financial Statements. As a result, all previous references to “minority interest” within these financial statements have been replaced with “noncontrolling interest.” Also, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of these standards, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in the Consolidated Financial Statements. We have adopted these standards on a retrospective basis. While this presentation differs from previous requirements under GAAP, it did not affect our net income and equity attributable to Holly Corporation stockholders.
(3)At December 31, 2008, HEP classified $29 million in credit agreement borrowings as short-term debt.
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 
EBITDAfrom continuing operations (1)
 $262,304  $528,897  $414,541 
             
  Years Ended December 31, 
  2009  2008  2007 
  (In thousands) 
             
Net cash provided by operating activities $211,545  $155,490  $422,737 
Net cash used for investing activities $(534,603) $(57,777) $(293,057)
Net cash provided by (used for) financing activities $406,849  $(151,277) $(189,428)
Capital expenditures $302,551  $418,059  $161,258 
EBITDA from continuing operations(1)
 $156,721  $259,387  $528,897 
(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 thisForm 10-K.

-47-

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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
  (In thousands) 
Sales and other revenues            
Refining(1)
 $4,786,937  $5,837,449  $4,790,164 
HEP(2)
  146,561   94,439   — 
Corporate and other  2,248   2,641   1,578 
Eliminations  (101,478)  (74,172)  — 
          
Consolidated $4,834,268  $5,860,357  $4,791,742 
          
             
Operating income (loss)            
Refining(1)
 $68,397  $210,252  $537,118 
HEP(2)
  70,373   37,082   — 
Corporate and other  (57,355)  (51,654)  (70,786)
Eliminations  (1,104)  —   — 
          
Consolidated $80,311  $195,680  $466,332 
          
(1) The Refining segment includes the operations of our Navajo, Refinery, Woods Cross Refineryand Tulsa Refineries 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

-39-

above tables.Asphalt. 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, specialty lubricant products, and includes our Navajo Refineryspecialty and Woods Cross Refinery.modified asphalt. The petroleum products produced by the Refining segment are primarily marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washingtonthe Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. The Refining segment also includesAdditionally, specialty lubricant products produced at our Tulsa Refinery are marketed throughout North America and are distributed in Central and South America. 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 and refinery tankage in Texas, New Mexico, Oklahoma and Utah, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma and Washington and refinery tankage in New Mexico and Utah.Washington. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through theirits pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at theirits storage tanks and terminals. TheAdditionally, HEP segment also includesowns a 70%25% interest in Rio Grande which also provides petroleum products transportation services.the SLC Pipeline that services refineries in the Salt Lake City, Utah area. 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.the SLC Pipeline.
Refining Operating Data
Our refinery operations include the Navajo, Refinery and the Woods Cross Refinery.and Tulsa Refineries. 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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
Consolidated
            
Crude charge (BPD)(1)
  142,430   100,680   103,490 
Refinery production (BPD)(2)
  151,420   110,850   113,270 
Sales of produced refined products (BPD)  151,580   111,950   115,050 
Sales of refined products (BPD)(3)
  155,820   120,750   126,800 
             
Refinery utilization(4)
  78.9%  89.7%  94.1%
             
Average per produced barrel(5)
            
Net sales $74.06  $108.83  $89.77 
Cost of products(6)
  66.85   97.87   73.03 
          
Refinery gross margin  7.21   10.96   16.74 
Refinery operating expenses(7)
  5.24   5.14   4.43 
          
Net operating margin $1.97  $5.82  $12.31 
          
(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.

-48-

 
(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 (our 2007 Navajo Refinery expansion) and by an additional 5,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion). During 2009, we increased our consolidated crude capacity by 15,000 BPSD in the first quarter of 2009 (our 2009 Navajo Refinery expansion), by 85,000 BPSD in the second quarter of 2009 (our June 2009 Tulsa Refinery west facility acquisition) and by 40,000 BPSD in the fourth quarter of 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 116,000256,000 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.
Results of Operations — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Summary
Income from continuing operations attributable to Holly Corporation stockholders for the year ended December 31, 2009 was $15.2 million ($0.30 per basic and diluted share) a $104 million decrease compared to $119.2 million ($2.37 per basic and $2.36 per diluted share) for the year ended December 31, 2008. Income from continuing operations decreased due principally to an overall decrease in refined gross margins in the second half of 2009. Overall refinery gross margins for the year ended December 31, 2009 were $7.21 per produced barrel compared to $10.96 for the year ended December 31, 2008.
Overall production levels for the year ended December 31, 2009 increased by 37% over 2008 due to production attributable to the operations of our recently acquired Tulsa Refinery facilities and production gains resulting from our recent Navajo and Woods Cross Refinery capacity expansions. Also impacting production levels was scheduled downtime for major maintenance turnarounds at the Navajo Refinery in the first quarter of 2009 and the Woods Cross Refinery in the third quarter of 2008. During the first quarter of 2009, we timed our Navajo Refinery turnaround to coincide with the completion of its 15,000 BPSD capacity expansion, increasing refining capacity to 100,000 BPSD.
Sales and Other Revenues
Sales and other revenues from continuing operations decreased 18% from $5,860.4 million for the year ended December 31, 2008 to $4,834.3 million for the year ended December 31, 2009, due principally to significantly lower refined product sales prices, partially offset by the effects of a 29% increase in volumes of refined products sold. The volume increase was primarily due to volumes attributable to our Tulsa Refinery operations. The average sales price we received per produced barrel sold decreased 32% from $108.83 for the year ended December 31, 2008 to $74.06 for the year ended December 31, 2009. Additionally, direct sales of excess crude oil also decreased in the current year. Sales and other revenues for the years ended December 31, 2009 and 2008, include $45.5 million and $19.3 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.
Cost of Products Sold
Cost of products sold decreased 20% from $5,280.7 million in 2008 to $4,238 million in 2009, due principally to the effects of significantly lower crude oil costs, partially offset by the effects of a 29% increase in volumes of 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 decreased 32% from $97.87 in 2008 to $66.85 in 2009.
Gross Refinery Margins
Gross refining margin per produced barrel decreased 34% from $10.96 in 2008 to $7.21 in 2009, due to a decrease in the average sales price we received per produced barrel sold, partially offset by the effects of a decrease in the average price we paid per produced barrel of crude oil and feedstocks. 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 statement of prices of refined products sold and costs of products purchased.

-40-

-49-

Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 34% from $265.7 million in 2008 to $356.9 million in 2009, due principally to costs attributable to the operations of our Tulsa Refinery commencing June 1, 2009 and the inclusion of HEP operating expense for a full twelve-month period in 2009 compared to ten months in 2008 due to our reconsolidation of HEP effective March 1, 2008. Additionally, there were certain increased costs at our existing facilities following the recently completed expansions, which were partially offset by lower utility costs. For the years ended December 2009 and 2008, operating expenses included $43.5 million and $33.4 million, respectively, in costs attributable to HEP operations.
General and Administrative Expenses
General and administrative expenses increased 9% from $55.3 million in 2008 to $60.3 million in 2009, due principally to costs associated with the support and integration of our Tulsa Refinery, increased payroll costs and increased professional fees and services. Additionally, general and administrative expenses for 2009 and 2008 include $5.3 million and $3.7 million, respectively, in costs attributable to HEP operations.
Depreciation and Amortization Expenses
Depreciation and amortization increased 57% from $63 million in 2008 to $98.8 million in 2009. The increase was due principally to depreciation and amortization attributable to our Tulsa Refinery and capitalized refinery improvement projects in 2008 and 2009, and the inclusion of HEP depreciation expense for a full twelve-month period during 2009 compared to ten months in 2008. For the year ended December 31, 2009 and 2008, depreciation and amortization expenses included $26.5 million and $18.4 million, respectively, in costs attributable to HEP operations.
Equity in Earnings of SLC Pipeline
HEP has a 25% joint venture interest in the SLC Pipeline that commenced pipeline operations effective March 2009. HEP’s equity in earnings of the SLC the SLC Pipeline was $1.9 million for the year ended December 31, 2009.
Interest Income
Interest income for the year ended December 31, 2009 was $5 million compared to $10.8 million for the year ended December 31, 2008, due principally to a decrease in investments in marketable debt securities.
Interest Expense
Interest expense was $40.3 million for the year ended December 31, 2009 compared to $24 million for the year ended December 31, 2008. The increase was due principally to interest attributable to increased long-term debt, including our 9.875% senior notes due 2017 (the “Holly Senior Notes”), and the inclusion of HEP interest expense for a full twelve-month period during 2009 compared to ten months in 2008. For the year ended December 31, 2009 and 2008, interest expense included $23.8 million and $21.5 million, respectively, in costs attributable to HEP operations. Additionally for the years ended December 31, 2009 and 2008, fair value adjustments attributable to HEP’s interest rate swaps resulted in non-cash interest expense of $.2 million and $2.3 million, respectively.
Acquisition Costs — Tulsa Refineries
During the year ended December 31, 2009, we incurred $3.1 million in acquisition costs related to our June 1, 2009 Tulsa Refinery west facility and our December 1, 2009 Tulsa Refinery east facility acquisitions.
Impairment of Equity Securities
For the year ended December 31, 2008, we recorded an impairment loss of $3.7 million that related to our 1,000,000 shares of Connacher common stock that we received in connection with our sale of the Montana refinery in 2006. This loss represents an other-than-temporary decline in the fair value of these equity securities during 2008.
Gain on Sale of HPI
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 million, resulting in a gain of $6 million.

-50-

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 for the year ended December 31, 2008 was $3 million representing our pro-rata share of earnings in HEP from January 1 through February 29, 2008.
Income Taxes
Income taxes decreased 88% from $64 million in 2008 to $7.5 million in 2009 due to significantly lower pre-tax earnings in 2009 compared to 2008. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 17% compared to 34.1% for the year ended December 31, 2008. Our effective tax rate calculation was affected by how the noncontrolling interest is classified on the income statement. Our actual effective tax rate did not decline.
Discontinued Operations
On December 1, 2009, HEP sold its 70% interest in Rio Grande resulting in a $14.5 million gain. Rio Grande operations generated net earnings of $4.4 million for the year ended December 31, 2009 compared to $2.9 million for the year ended December 31, 2008. This is presented before taking effect of HEP’s noncontrolling interest in the discontinued operations.
Noncontrolling Interest in Net Income
Noncontrolling interest holders’ share in earnings of HEP was $33.7 million for the year ended December 31, 2009 compared to $6.1 million in 2008. This increase was due principally to higher HEP earnings in 2009 compared to 2008 including HEP’s gain on the sale of Rio Grande, our decreased ownership in HEP and the inclusion of HEP consolidated results for a full twelve-month period in 2009 compared to ten months in 2008 due to our reconsolidation of HEP effective March 1, 2008.
Results of Operations — Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Summary
Net Income from continuing operations attributable to Holly Corporation stockholders for the year ended December 31, 2008 was $120.6$119.2 million ($2.402.37 per basic and $2.38$2.36 per diluted share), a $214.9 decrease 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, 2008Income from continuing operations 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%22% from $4,791.7 million for the year ended December 31, 2007 to $5,867.7$5,860.4 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 of 2008 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$19.3 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$23 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.

-51-

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 price 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%27% from $209.3 million in 2007 to $267.6$265.7 million in 2008, due principally to the inclusion of $35.2$33.4 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$69.2 million in 2007 to $54.9$55.3 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$3.7 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%45% from $43.5 million in 2007 to $63.8$63 million in 2008, due principally to the inclusion of $19.2$18.4 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.

-41-

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$3 million and $19.1 million for the years ended December 31, 2008 and 2007, respectively.
Minority InterestsImpairment of Equity Securities
Minority interests in income forFor 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 representswe recorded an impairment loss of $3.7 million during the year ended December 31, 2008 that relates to our 1,000,000 shares of Connacher common stock that waswe received in connection with our sale of the Montana Refineryrefinery in 2006 and we accounted for this as2006. This loss represents an other-than-temporary decline in the fair value of these securities.equity securities during 2008.
Gain on saleSale 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$6 million, resulting in a gain of $6.0$6 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$24 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$64 million in 2008 due to lower pre-tax earnings in 2008 compared to 2007. TheOur effective tax rate, for the year ended December 31, 2008before consideration of earnings attributable to noncontrolling interests was 35.0%34.1% compared to 33.1% for the yearyears ended December 31, 2007.2008 and 2007, respectively. 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

-42-

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.

-43--52-

Discontinued Operations
We had no income from discontinuedRio Grande operations for the year ended December 31, 2007, as our Montana Refinery operations have ceased. Income from discontinued operations was $19.7generated net earnings of $2.9 million for the year ended December 31, 2006 which consisted2008.
Noncontrolling Interest in Net Income
Noncontrolling interest holders’ share in earnings of a $14.0HEP was $6.1 million gain onfor the saleyear ended December 31, 2008, representing their pro-rata share of HEP earnings for the Montana Refinery, netperiod from March 1, 2009 (date 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 MarchHEP reconsolidation) through December 31, 2006.2008.
LIQUIDITY AND CAPITAL RESOURCES
Holly Credit Agreement
We consider all highly-liquid instruments withhave 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$370 million senior secured credit agreement expiring 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.
March 2013. In March 2008,April 2009, we entered into ana second amended and restated $175.0$300 million senior secured revolving credit agreement (the “Credit Agreement”) that amendsamended and restatesrestated our previous credit agreement in its entirety with Bank of America, N.A. as administrative agent and lender.one of a syndicate of lenders (the “Holly Credit Agreement”). Additionally, we upsized the credit agreement by $50 million in November 2009 and by an additional $20 million in December 2009 pursuant to the accordion feature. 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 andagreement may be used to fund working capital requirements, capital expenditures, permitted acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2008.2009. At December 31, 2008,2009, we had no outstanding borrowings and letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility.$56.3 million. At that level of usage, the unused commitment under our credit facilitythe Holly Credit Agreement was $172.5$313.7 million at December 31, 2008.2009.
Refinery gross margins were substantially reduced in the 2009 fourth quarter, which resulted in a fourth quarter loss. We expect to be in compliance with the Holly Credit Agreement covenant requirements as long as refinery margins show marked improvement over 2009 fourth quarter levels to be more in line with historical norms. If a situation were to arise in which margins stayed depressed for a prolonged period of time, we could potentially need to renegotiate certain covenants in the Credit Agreement.
There are currently a total of ninefourteen lenders under our $175.0 millionthe Holly Credit Agreement with individual commitments ranging from $15.0$15 million to $27.5$47.5 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,that would be available from the remaining lenders would be sufficient 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 Holly 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 Credit Agreement
HEP has a $300.0$300 million senior secured revolving credit agreement expiring in August 2011 (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 usedis available to fund working capital requirements, capital expenditures, acquisitions and working capital and / or other general partnership purposes. At December 31, 2009, HEP had outstanding borrowings totaling $206 million under the HEP Credit Agreement, with unused borrowing capacity of $94 million. 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, 20082009 consist of $5.3$2.5 million in cash and cash equivalents, $5.1$6.9 million in trade accounts receivable and other current assets, $354.1$458.5 million in property, plantproperties, plants and

-44-

equipment, net and $56.1$125.2 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., theirits 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 theirits 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 $171.0a $171 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$15 million to $40.0$40 million. If any particular lender could not honor its commitment, HEP hasbelieves the unused capacity that would be available under their credit agreement, which was $100.0 million as of December 31, 2008,from the remaining lenders would be sufficient to meet theirits 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 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.

-53-

Holly Senior Notes
In June 2009, we issued $200 million in aggregate principal amount of Holly Senior Notes. A portion of the $188 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa Refinery west facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the Holly Senior Notes that was used to fund the cash portion of our acquisition of Sinclair’s 75,000 BPSD refinery also located in Tulsa, Oklahoma.
The $300 million aggregate principal amount of Holly Senior Notes mature on June 15, 2017 and bear interest at 9.875%. The Holly Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. At any time when the Holly Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Holly Senior Notes.
HEP Senior Notes
The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP(the “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., theirits 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 theirits 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$35 million of the principal amount of the HEP Senior Notes.
At December 31, 2008,Holly Financing Obligation
On October 20, 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa Refinery west facility as well as certain crude oil pipeline receiving facilities to Plains for $40 million in cash. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the carrying amountexclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits with Plains for crude oil purchased by them and delivered to our Tulsa Refinery west facility for storage. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing obligation. As a result, we retained our assets on our books and established a liability representing the $40 million in proceeds received. Lease payments under the agreement are applied as a reduction to principal with the remaining portion as interest expense.
HEP Equity Offerings
In November 2009, HEP closed on a public offering of 2,185,000 of its common units including 285,000 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s long-term debt was as follows:December 1, 2009 asset acquisitions, to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
     
  (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 beginningAdditionally in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at2009, HEP closed a costpublic offering of $655.22,192,400 of its common units including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million or an average of $39.10 per share.were used to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.

-54-

We believe our current cash and cash equivalents, and marketable securities, along with future internally generated cash flow and funds available under our credit facilities will provide sufficient resources to fund currently planned capital projects and our planned integration of the Tulsa Refinery facilities, 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.future. In addition, components of our growth strategy

-45-

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.
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. As of December 31, 2009, we had cash and cash equivalents of $124.6 million and short-term investments in marketable securities of $1.2 million.
Cash and cash equivalents increased by $83.8 million during 2009. Net cash provided by operating activities and financing activities of $211.5 million and $406.8 million, respectively, exceeded cash used for investing activities of $534.6 million. Working capital increased by $189.4 million during 2009.
Cash Flows — Operating Activities
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net cash flows provided by operating activities were $211.5 million for the year ended December 31, 2009 compared to $155.5 million for the year ended December 31, 2008, an increase of $56 million. Net income for 2009 was $53.3 million, a decrease of $73.3 million from $126.6 million for 2008. Non-cash adjustments consisting of depreciation and amortization, interest rate swap adjustments, deferred income taxes, equity-based compensation, gain on the sale of assets and impairment of equity securities resulted in an increase to operating cash flows of $130.4 million for the year ended December 31, 2009 compared to $104.2 million for the year ended December 31, 2008. Additionally, SLC Pipeline earnings in excess of distributions decreased operating cash flows by $0.4 million in 2009 while distributions in excess of equity in earnings of HEP increased 2008 operating cash flows by $3.1 million. Changes in working capital items increased cash flows by $44 million in 2009 compared to a decrease of $37 million in 2008. For the year ended December 31, 2009, inventories decreased by $17.9 million compared to an increase of $15 million for 2008. Also for 2009, accounts receivable increased by $474.2 million compared to a decrease of $332 million for 2008 and accounts payable increased by $583.6 million compared to a decrease of $393.2 million for 2008. Additionally, for 2009, turnaround expenditures were $33.5 million compared to $34.8 million for 2008.
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$126.6 million, a decrease of $213.5$207.5 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. WorkingChanges in working capital items decreased cash flows by $37.0$37 million in 2008 compared to an increase of $15.0$15 million in 2007. For the year ended December 31, 2008, inventories decreased by $15.0$15 million compared to an increase of $11.0$11 million for 2007. Also for 2008, accounts receivable decreased by $332.0$332 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.

-55-

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, 2009 Compared to Year Ended December 31, 2008
Net cash flows used for investing activities were $534.6 million for 2009 compared to $57.8 million for 2008, an increase of $476.8 million. Cash expenditures for property, plant and equipment for 2009 totaled $302.6 million compared to $418.1 million for 2008. These include HEP capital expenditures of $33 million and $34.3 million for the years ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, we paid cash consideration of $267.1 million in connection with our Tulsa Refinery west and east facility acquisitions. Additionally, HEP paid cash consideration of $25.7 million upon its acquisition of logistics and storage assets from Sinclair and made a $25.5 million joint venture contribution to the SLC Pipeline. In December 2009, HEP sold its 70% interest in Rio Grande for $35 million. The cash proceeds received are presented net of Rio Grande’s December 1, 2009 cash balance of $3.1 million. Also in 2009, we invested $175.9 million in marketable securities and received proceeds of $230.3 million from sales and maturities of marketable securities. For the year ended December 31, 2008, we invested $769.1 million in marketable securities and received proceeds of $945.5 million from sales and maturities of marketable securities. Additionally, we received $171 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP on February 29, 2008 and have presented 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.
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$171 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.

-46-

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 newapproved capital budget for 20092010 is $159.6 million. Additionally, capital costs of $38.8 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $19.8$200 million notin capital costs in 2010, including the capital projects approved in prior years, and our expansion and feedstock flexibilityyears. Our capital spending for 2010 is comprised of $58.5 million for 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$12.6 million for projects at the Woods Cross Refinery, $0.4$63.2 for projects at the Tulsa Refinery, $60 million for marketing-related projects, $1.4our portion of the UNEV pipeline project, $2.1 million for asphalt plant projects and $1.3$3.6 million for othermarketing-related and miscellaneous projects. The following summarizes our key capital projects.

-56-

At the Navajo Refinery, we
We are proceeding with the integration project of our Tulsa Refinery west and east facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD. The integration project involves the installation of interconnect pipelines that will permit us to transfer various intermediate streams between the two facilities. We have also signed a 10-year agreement with a third party for the use of an additional line for the transfer of gasoline blend stocks which is currently in service. These interconnect lines will allow us to eliminate the sale of gas oil at a discount to WTI under our 5-year gas oil off take agreement with a third party, optimize gasoline blending, increase our utilization of better process technology, and reduce operating costs. Also, as part of the integration, we are planning to expand the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD, eliminating the need to construct a new diesel hydrotreater at our west facility as previously planned. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We are currently planning to complete the integration projects by the end of the 2010.
The combined Tulsa Refinery facilities also will be required to comply with MSAT2 regulations in order to meet new benzene reduction requirements for gasoline. We have elected to largely use existing equipment at the Tulsa Refinery east facility to split reformate from reformers at both west and east facilities and install a new benzene saturation unit to achieve the required benzene reduction at an estimated cost of approximately $15 million. Our Tulsa Refinery is required to meet MSAT2 1.3% benzene levels in gasoline beginning in July 2012 and we expect complete this project well before then. We will be required to buy credits until this project is complete, as required by law, beginning in 2011.
Our consent decree with the EPA requires recovery of sulfur from the refinery fuel gas system at the Tulsa Refinery west facility by the end of 2013. We estimate our investment to comply with the requirements will be approximately $20 million. The consent decree also requires shutdown, replacement, or installation of low NOx burners in three low pressure boilers by the end of 2013. We are still evaluating the best solution to this issue.
We believe that the synergy of the Tulsa Refinery west and east facilities operated as a single integrated facility will result in savings of approximately $110 million of expected capital expenditures related to ULSD compliance. Also as a result of the integrated facility, we expect to be able to reduce capital expenditures for the forthcoming benzene in gasoline requirements from approximately $30 million for the Tulsa Refinery west facility alone to approximately $15 million for the integrated complex. Even if we are able to realize the operating synergies of the integrated facility, our Tulsa Refinery will still require sulfur recovery investment, but we estimate combining the two refineries will reduce our net near-term capital expenditure requirements by approximately $125 million, excluding the cost to construct the pipelines that will integrate the west and east facilities.
Phase I of our Navajo Refinery major capital projects including expandingwas mechanically completed in March 2009 increasing 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.effective April 1, 2009. Phase I requiresrequired 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 totalunits at a cost of approximately $190 million.
We are nearing completion of phase I is now expectedII of the major capital projects at the Navajo Refinery. These improvements will provide the capability to be approximately $185.0 million. The added costs are associated with permit timing delays, scope changes dueprocess up to permit required pollution control equipment that was not anticipated, material cost escalation and increased labor rates.
40,000 BPSD of heavy type crudes. 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 mechanicallyThe solvent deasphalter unit was complete in the fourth quarter of 2009 and was originally estimated to cost $84.0 million.is in operation. The total cost of phase IIcrude / vacuum unit revamp is now expected to be to be completed in the first quarter of 2010. We expect the phase II project to cost approximately $96.0$100 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$21 million and are expected to be completed atabout the same time as the phase II project.projects.
The Navajo Refinery is also installing acurrently plans to comply with the new 100 ton per day sulfur recovery unit that is scheduled for mechanical completion earlyMSAT2 regulations by the fractionation of raw naphtha with existing equipment to achieve benzene in the first quarter of 2009.gasoline levels below 1.3%. 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 ablepurchase credits from the Woods Cross and Tulsa Refineries in order reduce benzene down to process 100,000 BPSDthe required 0.62%. Due to our acquisition of crudethe Tulsa Refinery facilities from Sunoco and Sinclair, our Navajo Refinery has until the end of 2012 to comply with upthe MSAT2 regulation because we have lost our small refiner’s exemption and as a large refiner we have 30 months 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.comply.

-47-

-57-

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.$122 million. The projects were completedmechanically complete in the fourth quarter of 2008. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the
Our Woods Cross refinery is required to meet new LSG specifications as requiredinstall a wet gas scrubber on its FCC unit by the EPA.
To fully take advantageend of 2012. We estimate the economics on thetotal cost to be $12 million. The MSAT2 solution for Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to theinvolves installing a new reformate splitter and a benzene saturation unit at an estimated cost of $18 million. Like our Navajo Refinery, our Woods Cross Refinery. HEP’s joint venture pipelineRefinery has until the end of 2012 to comply 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.MSAT2 regulations.
In December 2007, we entered intoUnder a definitive agreement with Sinclair, towe are jointly buildbuilding the UNEV Pipeline, 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 northNorth Las Vegas areas. Under the agreement, we own a 75% interest in the joint venture pipeline andwith Sinclair, ownsour joint venture partner, owning the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd,BPD, with the capacity for further expansion to 120,000 bpd.BPD. The total cost of the pipeline project including terminals is expected to be $300.0$275 million, with our share of the cost totaling $225.0$206 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 intoWe 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. Additionally in 2008, we purchased a terminal and rail facility located near Cedar City, Utah
We currently anticipate that will serve as a key component of our UNEV joint venture pipeline.
The UNEV project is inall regulatory approvals required to commence the final stageconstruction of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceedUNEV Pipeline will now be received duringby the end of the second quarter of 2009, we2010. Once such approvals 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 provisionsreceived, construction of the Omnibus Agreement with HEP, HEPpipeline will have an option to purchase these transportation assets upon our completion of these projects. We expect to complete these projects intake approximately nine months. Under this schedule, the fourthpipeline would become operational during the first quarter of 2009.2011.
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 thethat our 2009 Navajo Refinery capacity expansion projects at the Navajo and Woods Cross Refineriesproject will qualify for this deduction.

-48-

The above mentioned regulatoryRegulatory compliance items, includingsuch as the ULSD and LSG requirements mentioned above, or other presently existing or future environmental regulations / consent decrees 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 20092010 HEP capital budget is comprised of $3.7$4.8 million for maintenance capital expenditures and $2.2$6 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.

-58-

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, 2009 Compared to Year Ended December 31, 2008
Net cash flows provided by financing activities were $406.8 million for 2009 compared to net cash flows used for financing activities of $151.3 million for 2008, an increase of $558.1 million. During 2009, we received $287.9 million in net proceeds upon the issuance of the Holly Senior Notes, received and repaid $94 million in advances under the Holly Credit Agreement, received $40 million under a financing transaction with Plains, paid $30.1 million in dividends, purchased $1.2 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, received a $15.2 million contribution from our UNEV Pipeline joint venture partner and recognized $1.2 million in excess taxes on our equity based compensation. Also during this period, HEP received proceeds of $133 million upon the issuance of additional common units, received $239 million and repaid $233 million in advances under the HEP Credit Agreement and paid distributions of $33.2 million to noncontrolling interest holders. Additionally, we paid $8.8 million in deferred financing costs during the year ended December 31, 2009 that relate to the Holly Senior Notes issued in June 2009. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29 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 the amendment and restatement of the Holly 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 million contribution from our UNEV Pipeline joint venture partner, received $1 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 noncontrolling interest holders.
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$29 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 amendedthe amendment and restatedrestatement of the Holly 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$17 million contribution from our UNEV Pipeline joint venture partner, received $1.0$1 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 minoritynoncontrolling interest holders. During 2007, we purchased treasury stock of $207.2 million under our

-49-

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.

-59-

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, 20082009 in total and by period due beginning in 2009. Effective March 1, 2008, we reconsolidated HEP. As a result, the2010. The table below does not include our contractual obligations to HEP under our three long-term transportation agreements with HEP.as these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2.2, “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 
                
                     
      Payments Due by Period 
      Less than          Over 
Contractual Obligations and Commitments Total  1 Year  1-3 Years  3-5 Years  5 Years 
  (In thousands) 
Holly Corporation(1)(2)
                    
Long-term debt — principal(3)
 $339,809  $1,029  $2,469  $3,143  $333,168 
Long-term debt — interest(4)
  267,398   34,397   68,381   67,707   96,913 
Operating leases  40,116   10,448   14,130   6,827   8,711 
Hydrogen supply agreement(5)
  82,866   6,138   12,276   12,276   52,176 
Other service agreements(6)
  131,293   12,672   25,121   25,121   68,379 
                
                     
   861,482   64,684   122,377   115,074   559,347 
                     
Holly Energy Partners
                    
Long-term debt — principal(7)
  391,000   —   206,000   —   185,000 
Long-term debt — interest(8)
  71,415   15,643   26,866   23,125   5,781 
Pipeline operating and right of way leases  47,646   6,264   12,516   12,451   16,415 
Other agreements  7,626   837   1,149   960   4,680 
                
                     
   517,687   22,744   246,531   36,536   211,876 
                
                     
Total $1,379,169  $87,428  $368,908  $151,610  $771,223 
                
(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)(1) Amounts shown do not include obligations under a 10-year crude oil transportation agreements providing that we will ship quantities of crude oil with each agreement having initial terms of 10 years.agreement. Our obligations under these agreementsthe agreement are subject to certain conditions including completion of construction and expansion projects by the transportation companies. Ourcompany. We expect the shipping commitments shall begin upon

-50-

completion of these projects which we expectcommitment 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 on2011 upon 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 theexpected completion date of the pipeline.projects.
 
(4)(2) 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$2 million as of December 31, 2008,2009 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 1213 to the Consolidated Financial Statements.
 
(3)Our long-term debt consists of the $300 million principal balance on the Holly Senior Notes and a long-term financing obligation having principal balance of $39.8 million at December 31, 2009.
(4)Interest payments consist of interest on the 9.875% Holly Senior Notes and on our long-term financing obligation.
(5)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 through 2023. 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.
(6)Includes: $131.2 million for transportation of natural gas and feedstocks to our refineries under contracts expiring between 2016 and 2024; and various service contracts with expiration dates through 2011.
(7) HEP’s long-term debt consists of the $185.0$185 million principal balance on the HEP Senior Notes and $171.0$206 million of outstanding principal under the HEP Credit Agreement that has been classified as long-term debt.Agreement.
 
(6)(8) Interest payments consist of interest on HEP’sthe 6.25% HEP Senior Notes and interest on long-term debt under the HEP Credit Agreement. Interest under the credit agreement debt is based on thean effective interest rate of 2.21%1.98% at December 31, 2008.2009.

-60-

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.GAAP. 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, 2008,2009, many of 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, 2008,2009, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $33.0$207 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.

-51-

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, 2009, 2008 2007 and 2006.2007.
Variable Interest Entity
HEP is a variableVIE which under GAAP is defined as a legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, as defined under Financial Accounting Standards Board Interpretation No. 46R.or have voting rights that are not proportionate to their economic interest. Under the provisions of FIN No. 46R,GAAP, HEP’s purchaseacquisition of the Crude Pipelines and Tankage Assets in 2008 qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, weHEP and determined that HEP continued to qualify as a VIE, and furthermore, 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 consolidated financial statements include the results of HEP.

-61-

Additionally, HEP’s 2009 asset acquisitions and the HEP May and November 2009 equity offerings qualified as reconsideration events. Following each of these transactions, we reassessed our beneficial interest in HEP and determined that HEP continued to qualify as a VIE and that our beneficial interest exceeds 50%.
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
StatementIn June 2009, new accounting standards were issued that replace the previous quantitative-based risk and rewards calculation provided under GAAP with a qualitative approach in determining whether an entity is the primary beneficiary of Financial Accounting Standard (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements —a VIE. Additionally, these standards require an Amendmententity to assess on an ongoing basis whether it is the primary beneficiary 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 deconsolidationVIE 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 theenhances disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies relatedwith respect 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 isinvolvement in a VIE. These standards are effective for fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. This standard is effective as of January 1, 20092010 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

-52-

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.
HEP uses interest rate swaps (derivative instruments) to manage its exposure to interest rate risk. As of December 31, 2008,2009, HEP hadhas three interest rate swap contracts.
HEP entered intohas an interest rate swap to hedge theirits exposure to the cash flow risk caused by the effects of LIBORLondon Interbank Borrowed Rate (“LIBOR”) changes on the $171.0$171 million HEP Credit Agreement advance that HEPwas used to finance theirHEP’s purchase of the Crude Pipelines and Tankage Assets from us. This interest rate swap effectively converts their $171.0the $171 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 this2009. This swap contract ismatures in 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 theirits 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$171 million variable rate debt resulting from changes in the London Interbank Offered Rate (“LIBOR”).LIBOR. Under hedge accounting, HEP adjusts theirthe cash flow hedge on a quarterly basis to its fair value on a quarterly basis with a corresponding offsetthe offsetting fair value adjustment 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$171 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008,2009, HEP had no ineffectiveness on theirits cash flow hedge.
HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0$60 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$60 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%1.41% as of December 31, 2008.2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.

-62-

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$60 million of theirits 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$60 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.
Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60 million in outstanding principal under the HEP Senior Notes. HEP dedesignated this hedge in October 2008. At that time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the dedesignation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.
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 entrythe offsetting fair value adjustment to interest expense. For the yearyears ended December 31, 2009 and 2008, HEP recognized an increase of $0.2 million and $2.3 million, respectively, in interest expense attributable toas a result of 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.

-53-

Additional information on HEP’s interest rate swaps as of December 31, 2009 is as follows:
                        
 Balance Sheet Location of   Balance Sheet Location of Offsetting   
Interest Rate Swaps Location Fair Value Offsetting Balance Offsetting Amount Location Fair Value Balance Offsetting Amount 
 (In thousands)    (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		)
)
Fixed-to-variable interest rate swap — Other assets $2,294 Long-term debt — HEP $(1,791)(1)
$60 million of 6.25% HEP Senior Notes   Equity  (1,942)(2)
   Interest expense  1,439(3)
                     
                 
   $4,079    $(4,079)   $2,294   $(2,294)
                     
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 
Cash flow hedge — $171 million
LIBOR based debt		 Other long-term liabilities $(9,141) Accumulated other comprehensive loss $9,141 
     
Variable-to-fixed interest rate swap — Other long-term liabilities Equity  4,166(2)
$60 million    (2,555) Interest expense  (1,611)
                     
                 
   $(17,133)   $17,133    $(11,696)   $11,696 
                     
(1)Represents unamortized balance of dedesignated hedge premium.
(2)Represents prior year charges to interest expense.
(3)Net of amortization of premium attributable to dedesignated hedge.
On January 29, 2010, HEP received notice from the counterparty that it is exercising its option to cancel the Variable Rate Swap on March 1, 2010, pursuant to the terms of the swap contract. HEP will receive a cancellation premium of $1.9 million.
We have reviewedHEP reviews publicly available information on ourits 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 haveThese counterparties consist of large financial institutions. HEP has not experienced, nor do wedoes it expect to experience, any difficulty in the counterparties honoring their respective commitments.
The market risk inherent in our fixed-rate debt and positions is the potential change arising from increases or decreases in interest rates as discussed below.

-63-

At December 31, 2009, outstanding principal under the Holly and HEP Senior Notes were $300 million and $185 million, respectively. By means of HEP’s interest rate swap contracts, HEP has effectively converted the 6.25% fixed rate on $60 million of the HEP Senior Notes to a fixed rate of 4.75%. For the fixed rate Holly and HEP Senior Notes, changes in interest rates would generally affect fair value of the debt, but not our earnings or cash flows. At December 31, 2009, the estimated fair value of the Holly Senior Notes and the HEP Senior Notes were $318 million and $177.6 million, respectively. We investestimate that a substantialhypothetical 10% change in the yield-to-maturity rates applicable to the senior notes would result in an approximate fair value change of $9.9 million to the Holly Senior Notes and a $5.5 million change to the HEP Senior Notes.
For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2009, borrowings outstanding under the HEP Credit Agreement were $206 million. By means of its cash flow hedge, HEP has effectively converted the variable rate on $171 million of outstanding principal to a fixed rate of 5.49%. For the unhedged $35 million portion, of availablea hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.
At December 31, 2009, cash and cash equivalents included investments in investment grade, highly liquid investments with maturities of three months or less at the time of purchase and hence the interest rate market risk implicit in these cash investments is low. We also investDue to the remaindershort-term nature of availableour cash in portfolios of highly rated marketable debt securities, primarily issued by government entities, that have an average remaining duration (including anyand cash equivalents, invested) of not greater than one year and hence the interest rate market risk implicit in these investments is also low. Aa hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in the market interest rate over the next year would not materially impactrates on 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.investment portfolio.
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.

-54-

-64-

Item 7A.
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;GAAP; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements.statements, with the exception of EBITDA from discontinued operations. 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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (In thousands) 
 (In thousands)  
Income from continuing operations $120,558 $334,128 $246,898  $36,343 $123,718 $334,128 
Add provision for income tax 64,826 165,316 136,603 
Subtract noncontrolling interest in income from continuing operations  (21,134)  (4,512) — 
Add income tax provision 7,460 64,028 165,316 
Add interest expense 23,955 1,086 1,076  40,346 23,955 1,086 
Subtract interest income  (10,824)  (15,089)  (9,757)  (5,045)  (10,797)  (15,089)
Add depreciation and amortization 63,789 43,456 39,721  98,751 62,995 43,456 
              
EBITDA from continuing operations $262,304 $528,897 $414,541  $156,721 $259,387 $528,897 
              
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.

-55-

-65-

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 three refineries on a consolidated basis is calculated as shown below.
                        
 Years Ended December 31,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
Average per produced barrel:  
  
Navajo Refinery
  
Net sales $108.52 $89.68 $79.62  $73.15 $108.52 $89.68 
Less cost of products 98.97 74.10 64.25  65.95 98.97 74.10 
              
Refinery gross margin $9.55 $15.58 $15.37  $7.20 $9.55 $15.58 
              
  
Woods Cross Refinery
  
Net sales $110.07 $90.09 $82.09  $70.25 $110.07 $90.09 
Less cost of products 93.47 69.40 64.99  58.98 93.47 69.40 
              
Refinery gross margin $16.60 $20.69 $17.10  $11.27 $16.60 $20.69 
              
  
Tulsa Refinery
 
Net sales $78.89 $— $— 
Less cost of products 74.56 — — 
       
Refinery gross margin $4.33 $— $— 
       
 
Consolidated
  
Net sales $108.83 $89.77 $80.21  $74.06 $108.83 $89.77 
Less cost of products 97.87 73.03 64.43  66.85 97.87 73.03 
              
Refinery gross margin $10.96 $16.74 $15.78  $7.21 $10.96 $16.74 
              
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 three refineries on a consolidated basis is calculated as shown below.
                        
 Years Ended December 31,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
Average per produced barrel:  
  
Navajo Refinery
  
Refinery gross margin $9.55 $15.58 $15.37  $7.20 $9.55 $15.58 
Less refinery operating expenses 4.58 4.30 4.74  4.81 4.58 4.30 
              
Net operating margin $4.97 $11.28 $10.63  $2.39 $4.97 $11.28 
              
  
Woods Cross Refinery
  
Refinery gross margin $16.60 $20.69 $17.10  $11.27 $16.60 $20.69 
Less refinery operating expenses 7.42 4.86 5.13  6.60 7.42 4.86 
              
Net operating margin $9.18 $15.83 $11.97  $4.67 $9.18 $15.83 
              
  
Tulsa Refinery
 
Refinery gross margin $4.33 $— $— 
Less refinery operating expenses 5.25 — — 
       
Net operating margin $(0.92) $— $— 
       
 
Consolidated
  
Refinery gross margin $10.96 $16.74 $15.78  $7.21 $10.96 $16.74 
Less refinery operating expenses 5.14 4.43 4.83  5.24 5.14 4.43 
              
Net operating margin $5.82 $12.31 $10.95  $1.97 $5.82 $12.31 
              

-56-

-66-

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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
  (Dollars in thousands, except per barrel amounts) 
Navajo Refinery
            
Average sales price per produced barrel sold $73.15  $108.52  $89.68 
Times sales of produced refined products sold (BPD)  87,140   89,580   88,920 
Times number of days in period  365   366   365 
          
Refined product sales from produced products sold $2,326,616  $3,557,967  $2,910,636 
          
             
Woods Cross Refinery
            
Average sales price per produced barrel sold $70.25  $110.07  $90.09 
Times sales of produced refined products sold (BPD)  26,870   22,370   26,130 
Times number of days in period  365   366   365 
          
Refined product sales from produced products sold $688,980  $901,189  $859,229 
          
             
Tulsa Refinery
            
Average sales price per produced barrel sold $78.89  $—  $— 
Times sales of produced refined products sold (BPD)  37,570   —   — 
Times number of days in period  365   —   — 
          
Refined product sales from produced products sold $1,081,823  $—  $— 
          
             
Sum of refined product sales from produced products sold from our three refineries(4)
 $4,097,419  $4,459,156  $3,769,865 
Add refined product sales from purchased products and rounding(1)
  106,969   384,073   383,396 
          
Total refined products sales  4,204,388   4,843,229   4,153,261 
Add direct sales of excess crude oil(2)
  453,958   860,642   491,150 
Add other refining segment revenue(3)
  128,591   133,578   145,753 
          
Total refining segment revenue  4,786,937   5,837,449   4,790,164 
Add HEP segment sales and other revenues  146,561   94,439   — 
Add corporate and other revenues  2,248   2,641   1,578 
Subtract consolidations and eliminations  (101,478)  (74,172)  — 
          
Sales and other revenues $4,834,268  $5,860,357  $4,791,742 
          
(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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (Dollars in thousands, except per barrel amounts) 
 (Dollars in thousands, except per barrel amounts)  
Average sales price per produced barrel sold $108.83 $89.77 $80.21  $74.06 $108.83 $89.77 
Times sales of produced refined products sold (BPD) 111,950 115,050 105,090  151,580 111,950 115,050 
Times number of days in period 366 365 365  365 366 365 
              
Refined product sales from produced products sold $4,459,156 $3,769,865 $3,076,726  $4,097,419 $4,459,156 $3,769,865 
              

-57-

-67-

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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
  (Dollars in thousands, except per barrel amounts) 
Navajo Refinery
            
Average cost of products per produced barrel sold $65.95  $98.97  $74.10 
Times sales of produced refined products sold (BPD)  87,140   89,580   88,920 
Times number of days in period  365   366   365 
          
Cost of products for produced products sold $2,097,612  $3,244,858  $2,404,975 
          
             
Woods Cross Refinery
            
Average cost of products per produced barrel sold $58.98  $93.47  $69.40 
Times sales of produced refined products sold (BPD)  26,870   22,370   26,130 
Times number of days in period  365   366   365 
          
Cost of products for produced products sold $578,449  $765,278  $661,899 
          
             
Tulsa Refinery
            
Average cost of products per produced barrel sold $74.56  $—  $— 
Times sales of produced refined products sold (BPD)  37,570   —   — 
Times number of days in period  365   —   — 
          
Cost of products for produced products sold $1,022,445  $—  $— 
          
             
Sum of cost of products for produced products sold from our three refineries(4)
 $3,698,506  $4,010,136  $3,066,874 
Add refined product costs from purchased products sold and rounding(1)
  114,650   389,944   374,432 
          
Total refined cost of products sold  3,813,156   4,400,080   3,441,306 
Add crude oil cost of direct sales of excess crude oil(2)
  449,488   853,360   492,222 
Add other refining segment cost of products sold(3)
  75,229   101,144   69,960 
          
Total refining segment cost of products sold  4,337,873   5,354,584   4,003,488 
Subtract consolidations and eliminations  (99,865)  (73,885)  — 
          
Cost of products sold (exclusive of depreciation and amortization) $4,238,008  $5,280,699  $4,003,488 
          
(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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (Dollars in thousands, except per barrel amounts) 
 (Dollars in thousands, except per barrel amounts)  
Average cost of products per produced barrel sold $97.87 $73.03 $64.43  $66.85 $97.87 $73.03 
Times sales of produced refined products sold (BPD) 111,950 115,050 105,090  151,580 111,950 115,050 
Times number of days in period 366 365 365  365 366 365 
              
Cost of products for produced products sold $4,010,136 $3,066,874 $2,471,285  $3,698,506 $4,010,136 $3,066,874 
              

-58-

-68-

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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
  (Dollars in thousands, except per barrel amounts) 
Navajo Refinery
            
Average refinery operating expenses per produced barrel sold $4.81  $4.58  $4.30 
Times sales of produced refined products sold (BPD)  87,140   89,580   88,920 
Times number of days in period  365   366   365 
          
Refinery operating expenses for produced products sold $152,987  $150,161  $139,560 
          
             
Woods Cross Refinery
            
Average refinery operating expenses per produced barrel sold $6.60  $7.42  $4.86 
Times sales of produced refined products sold (BPD)  26,870   22,370   26,130 
Times number of days in period  365   366   365 
          
Refinery operating expenses for produced products sold $64,730  $60,751  $46,352 
          
             
Tulsa Refinery
            
Average refinery operating expenses per produced barrel sold $5.25  $—  $— 
Times sales of produced refined products sold (BPD)  37,570   —   — 
Times number of days in period  365   —   — 
          
Refinery operating expenses for produced products sold $71,994  $—  $— 
          
             
Sum of refinery operating expenses per produced products sold from our three refineries(2)
 $289,711  $210,912  $185,912 
Add other refining segment operating expenses and rounding(1)
  23,609   21,599   23,357 
          
Total refining segment operating expenses  313,320   232,511   209,269 
Add HEP segment operating expenses  44,003   33,353   — 
Add corporate and other costs  (468)  (159)  12 
          
Operating expenses (exclusive of depreciation and amortization) $356,855  $265,705  $209,281 
          
(1) 
Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of Holly Asphalt Company.Asphalt.
 
(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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (Dollars in thousands, except per barrel amounts) 
 (Dollars in thousands, except per barrel amounts)  
Average refinery operating expenses per produced barrel sold $5.14 $4.43 $4.83  $5.24 $5.14 $4.43 
Times sales of produced refined products sold (BPD) 111,950 115,050 105,090  151,580 111,950 115,050 
Times number of days in period 366 365 365  365 366 365 
              
Refinery operating expenses for produced products sold $210,912 $185,912 $185,396  $289,711 $210,912 $185,912 
              
Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues
                        
 Years Ended December 31,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
 (Dollars in thousands, except per barrel amounts)  (Dollars in thousands, except per barrel amounts) 
Navajo Refinery
  
Net operating margin per barrel $4.97 $11.28 $10.63  $2.39 $4.97 $11.28 
Add average refinery operating expenses per produced barrel 4.58 4.30 4.74  4.81 4.58 4.30 
              
Refinery gross margin per barrel 9.55 15.58 15.37  7.20 9.55 15.58 
Add average cost of products per produced barrel sold 98.97 74.10 64.25  65.95 98.97 74.10 
              
Average sales price per produced barrel sold $108.52 $89.68 $79.62  $73.15 $108.52 $89.68 
Times sales of produced refined products sold (BPD) 89,580 88,920 79,940  87,140 89,580 88,920 
Times number of days in period 366 365 365  365 366 365 
              
Refined product sales from produced products sold $3,557,967 $2,910,636 $2,323,160  $2,326,616 $3,557,967 $2,910,636 
              

-59-

-69-

             
  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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
  (Dollars in thousands, except per barrel amounts) 
Woods Cross Refinery
            
Net operating margin per barrel $4.67  $9.18  $15.83 
Add average refinery operating expenses per produced barrel  6.60   7.42   4.86 
          
Refinery gross margin per barrel  11.27   16.60   20.69 
Add average cost of products per produced barrel sold  58.98   93.47   69.40 
          
Average sales price per produced barrel sold $70.25  $110.07  $90.09 
Times sales of produced refined products sold (BPD)  26,870   22,370   26,130 
Times number of days in period  365   366   365 
          
Refined product sales from produced products sold $688,980  $901,189  $859,229 
          
             
Tulsa Refinery
            
Net operating margin per barrel $(0.92) $—  $— 
Add average refinery operating expenses per produced barrel  5.25   —   — 
          
Refinery gross margin per barrel  4.33   —   — 
Add average cost of products per produced barrel sold  74.56   —   — 
          
Average sales price per produced barrel sold $78.89  $—  $— 
Times sales of produced refined products sold (BPD)  37,570   —   — 
Times number of days in period  365   —   — 
          
Refined product sales from produced products sold $1,081,823  $—  $— 
          
             
Sum of refined product sales from produced products sold from our three refineries(4)
 $4,097,419  $4,459,156  $3,769,865 
Add refined product sales from purchased products and rounding(1)
  106,969   384,073   383,396 
          
Total refined product sales  4,204,388   4,843,229   4,153,261 
Add direct sales of excess crude oil(2)
  453,958   860,642   491,150 
Add other refining segment revenue(3)
  128,591   133,578   145,753 
          
Total refining segment revenue  4,786,937   5,837,449   4,790,164 
Add HEP segment sales and other revenues  146,561   94,439   — 
Add corporate and other revenues  2,248   2,641   1,578 
Subtract consolidations and eliminations  (101,478)  (74,172)  — 
          
Sales and other revenues $4,834,268  $5,860,357  $4,791,742 
          
(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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (Dollars in thousands, except per barrel amounts) 
 (Dollars in thousands, except per barrel amounts)  
Net operating margin per barrel $5.82 $12.31 $10.95  $1.97 $5.82 $12.31 
Add average refinery operating expenses per produced barrel 5.14 4.43 4.83  5.24 5.14 4.43 
              
Refinery gross margin per barrel 10.96 16.74 15.78  7.21 10.96 16.74 
Add average cost of products per produced barrel sold 97.87 73.03 64.43  66.85 97.87 73.03 
              
Average sales price per produced barrel sold $108.83 $89.77 $80.21  $74.06 $108.83 $89.77 
Times sales of produced refined products sold (BPD) 111,950 115,050 105,090  151,580 111,950 115,050 
Times number of days in period 366 365 365  365 366 365 
              
Refined product sales from produced products sold $4,459,156 $3,769,865 $3,076,726  $4,097,419 $4,459,156 $3,769,865 
              

-60-

-70-

Item 8.
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, 20082009 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, 2008,2009, the Company maintained effective internal control over financial reporting.
The Company acquired two refinery facilities located in Tulsa, Oklahoma during 2009, one from an affiliate of Sunoco, Inc. on June 1, 2009 and another from an affiliate of Sinclair Oil Company on December 1, 2009. Management has excluded the operations of these facilities from its assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009. These facilities represent 23%, 2% and 22% of our total assets, net assets and revenues, respectively, as of December 31, 2009. We plan to fully integrate the operations of these facilities into our assessment of the effectiveness of internal control over financial reporting in 2010.
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, 2008.2009. That report appears on page 62.72.

-61-

-71-

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, 2008,2009, 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.
As indicated in the accompanying, Management’s Report on its Assessment of the Company’s Internal Control Over Financial Reporting, management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the two refinery facilities located in Tulsa, Oklahoma, one acquired from an affiliate of Sunoco, Inc. and another from an affiliate of Sinclair Oil Company which are included in the December 31, 2009 consolidated financial statements of Holly Corporation and represent 23%, 2% and 22% of total assets, net assets and revenues, respectively, as of and for the year ended December 31, 2009. Our audit of internal control over financial reporting of Holly Corporation also did not include an evaluation of the internal control over financial reporting of the two acquired refinery facilities.
In our opinion, Holly Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,2009, 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, 20082009 and 2007,2008, 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, 20082009 and our report dated February 27, 200926, 2010 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 27, 200926, 2010

-62-

-72-

Index to Consolidated Financial Statements
     
  Page
  Reference
Report of Independent Registered Public Accounting Firm
  6475 
     
Consolidated Balance Sheets at December 31, 20082009 and 20072008
  6576 
     
Consolidated Statements of Income for the years ended December 31, 2009, 2008 2007 and 20062007
  6677 
     
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 2007 and 20062007
  6778 
     
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009, 2008 2007 and 20062007
  6879 
     
Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 2007 and 20062007
  6980 
     
Notes to Consolidated Financial Statements
  7081
 

-63-

-74-

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, 20082009 and 2007,2008, 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, 2008.2009. 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, 20082009 and 2007,2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008,2009, 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, 2008,2009, 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, 200926, 2010 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 27, 200926, 2010

-64-

-75-

HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)
        
         December 31, December 31, 
 December 31, December 31,  2009 2008 
 2008 2007  
ASSETS
  
Current assets:
  
Cash and cash equivalents $40,805 $94,369  $124,596 $39,244 
Marketable securities 49,194 158,233  1,223 49,194 
  
Accounts receivable: Product and transportation 128,337 242,392 
Accounts receivable: 
Product and transportation 292,310 127,192 
Crude oil resales 161,427 366,226  470,145 161,427 
Related party receivable — 6,151 
          
 289,764 614,769  762,455 288,619 
  
Inventories: Crude oil and refined products 107,811 118,308 
Inventories: 
Crude oil and refined products 259,582 107,811 
Materials and supplies 17,924 22,322  43,931 17,924 
          
 125,735 140,630  303,513 125,735 
  
Income taxes receivable 6,350 16,356  38,072 6,350 
Prepayments and other 18,775 10,264  50,957 18,775 
Current assets of discontinued operations 2,195 2,706 
          
Total current assets
 530,623 1,034,621  1,283,011 530,623 
  
Properties, plants and equipment, at cost 1,509,701 802,820  2,001,855 1,462,963 
Less accumulated depreciation  (304,379)  (271,970)  (371,885)  (290,039)
          
 1,205,322 530,850  1,629,970 1,172,924 
  
Marketable securities (long-term) 6,009 77,182  — 6,009 
  
Other assets: Turnaround costs 34,309 8,705 
Other assets: 
Turnaround costs 53,463 34,309 
Goodwill 27,542 —  81,602 27,542 
Intangibles and other 70,420 12,587  97,893 70,420 
          
 132,271 21,292  232,958 132,271 
Non-current assets of discontinued operations — 32,398 
          
Total assets
 $1,874,225 $1,663,945  $3,145,939 $1,874,225 
          
  
LIABILITIES AND STOCKHOLDERS’ EQUITY
  
Current liabilities:
  
Accounts payable $391,142 $782,976  $975,155 $390,438 
Accrued liabilities 42,016 35,104  49,957 41,785 
Short-term debt — Holly Energy Partners 29,000 —  — 29,000 
Current liabilities of discontinued operations — 935 
          
Total current liabilities
 462,158 818,080  1,025,112 462,158 
  
Long-term debt — Holly Corporation 328,260 — 
Long-term debt — Holly Energy Partners 341,914 —  379,198 341,914 
Deferred income taxes 69,491 38,933  124,585 69,491 
Other long-term liabilities 64,330 36,712  81,003 64,330 
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 
Equity:
 
Holly Corporation 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; 76,359,006 and 73,543,873 shares issued as of December 31, 2009 and 2008, respectively 764 735 
Additional capital 121,298 109,125  195,565 121,298 
Retained earnings 1,145,388 1,054,974  1,134,341 1,145,388 
Accumulated other comprehensive loss  (35,081)  (19,076)  (25,700)  (35,081)
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)
Common stock held in treasury, at cost — 23,292,737 and 23,600,653 shares as of December 31, 2009 and 2008, respectively  (685,931)  (690,800)
          
Total stockholders’ equity
 541,540 593,794 
Total Holly Corporation stockholders’ equity
 619,039 541,540 
 
Noncontrolling interest
 588,742 394,792 
          
Total liabilities and stockholders’ equity
 $1,874,225 $1,663,945 
Total equity
 1,207,781 936,332 
          
Total liabilities and equity
 $3,145,939 $1,874,225 
     
See accompanying notes.

-65-

-76-

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)
            
             Years Ended December 31, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  
Sales and other revenues
 $5,867,668 $4,791,742 $4,023,217  $4,834,268 $5,860,357 $4,791,742 
  
Operating costs and expenses:
  
Cost of products sold (exclusive of depreciation and amortization) 5,280,699 4,003,488 3,349,404  4,238,008 5,280,699 4,003,488 
Operating expenses (exclusive of depreciation and amortization) 267,570 209,281 208,460  356,855 265,705 209,281 
General and administrative expenses (exclusive of depreciation and amortization) 54,906 68,773 63,255  60,343 55,278 69,185 
Depreciation and amortization 63,789 43,456 39,721  98,751 62,995 43,456 
Exploration expenses, including dry holes 372 412 486 
              
Total operating costs and expenses
 5,667,336 4,325,410 3,661,326  4,753,957 5,664,677 4,325,410 
              
  
Income from operations
 200,332 466,332 361,891  80,311 195,680 466,332 
  
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 — — 
Equity in earnings of SLC Pipeline 1,919 — — 
Interest income 10,824 15,089 9,757  5,045 10,797 15,089 
Interest expense  (23,955)  (1,086)  (1,076)  (40,346)  (23,955)  (1,086)
Acquisition costs — Tulsa refineries  (3,126) — — 
Impairment of equity securities —  (3,724) — 
Gain on sale of Holly Petroleum, Inc. — 5,958 — 
Equity in earnings of Holly Energy Partners — 2,990 19,109 
              
  (14,948) 33,112 21,610   (36,508)  (7,934) 33,112 
              
Income from continuing operations before income taxes
 185,384 499,444 383,501  43,803 187,746 499,444 
  
Income tax provision:  
Current 31,892 142,245 126,181   (30,062) 31,094 142,245 
Deferred 32,934 23,071 10,422  37,522 32,934 23,071 
              
 64,826 165,316 136,603  7,460 64,028 165,316 
              
Income from continuing operations
 120,558 334,128 246,898  36,343 123,718 334,128 
  
Discontinued operations
  
Income from discontinued operations, net of taxes 4,425 2,918 — 
Gain on sale of discontinued operations, net of taxes 12,501 — — 
       
Income from discontinued operations — — 5,660  16,926 2,918 — 
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  53,269 126,636 334,128 
        
Less net income attributable to noncontrolling interest 33,736 6,078 — 
        
Basic earnings per share:
 
Continuing operations $2.40 $6.09 $4.33 
Discontinued operations — — 0.35 
 
Net income attributable to Holly Corporation stockholders
 $19,533 $120,558 $334,128 
       
 
Earnings attributable to Holly Corporation stockholders:
 
Income from continuing operations $15,209 $119,206 $334,128 
Income from discontinued operations 4,324 1,352 — 
              
Net income $2.40 $6.09 $4.68  $19,533 $120,558 $334,128 
              
  
Diluted earnings per share:
 
Continuing operations $2.38 $5.98 $4.24 
Discontinued operations — — 0.34 
Earnings per share attributable to Holly Corporation stockholders — basic:
 
Income from continuing operations $0.30 $2.37 $6.09 
Income from discontinued operations 0.09 0.03 — 
       
Net income $0.39 $2.40 $6.09 
       
 
Earnings per share attributable to Holly Corporation stockholders — diluted:
 
Income from continuing operations $0.30 $2.36 $5.98 
Income from discontinued operations 0.09 0.02 — 
              
Net income $2.38 $5.98 $4.58  $0.39 $2.38 $5.98 
              
  
Average number of common shares outstanding:
  
Basic 50,202 54,852 56,976  50,418 50,202 54,852 
Diluted 50,549 55,850 58,210  50,603 50,549 55,850 
See accompanying notes.

-66-

-77-

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)
                        
 Years Ended December 31,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
Cash flows from operating activities:
  
Net income $120,558 $334,128 $266,566  $53,269 $126,636 $334,128 
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 
Depreciation and amortization (includes discontinued operations) 99,633 63,789 43,456 
SLC Pipeline earnings in excess of distributions  (419) — — 
Deferred income taxes 37,522 32,934 23,071 
Distributions in excess of equity in earnings of Holly Energy Partners — 3,067 3,688 
Equity based compensation expense 7,467 9,993 5,507  7,549 7,467 9,993 
Gain on sale of assets, before income taxes  (5,958) —  (22,328)  (14,479)  (5,958) — 
Change in fair value — interest rate swaps 2,282 — —  175 2,282 — 
Impairment of equity securities 3,724 — —  — 3,724 — 
(Increase) decrease in current assets:  
Accounts receivable 331,978  (216,295) 12,059   (474,205) 331,978  (216,295)
Inventories 15,006  (10,955)  (33,792)  (17,904) 15,006  (10,955)
Income taxes receivable 10,006  (7,301)  (9,055)  (33,270) 10,006  (7,301)
Prepayments and other  (398) 1,817 5,890   (15,816)  (398) 1,817 
Increase (decrease) in current liabilities:  
Accounts payable  (393,186) 264,217  (26,370) 583,550  (393,186) 264,217 
Accrued liabilities  (2,149)  (16,476) 15,665  1,651  (2,149)  (16,476)
Income taxes payable 1,781 —  (5,323) — 1,781 — 
Turnaround expenditures  (34,751)  (2,669)  (7,672)  (33,541)  (34,751)  (2,669)
Other, net  (7,701)  (3,937)  (11,593) 17,830  (6,738)  (3,937)
              
Net cash provided by operating activities
 155,490 422,737 245,183  211,545 155,490 422,737 
  
Cash flows from investing activities:
  
Additions to properties, plants and equipment — Holly Corporation  (383,742)  (161,258)  (120,429)  (269,552)  (383,742)  (161,258)
Additions to properties, plants and equipment — Holly Energy Partners  (34,317) — —   (32,999)  (34,317) — 
Acquisition of Tulsa Refinery facilities — Holly Corporation  (267,141) — — 
Acquisition of logistics assets from Sinclair Oil Company — Holly Energy Partners  (25,665) — — 
Investment in SLC Pipeline — Holly Energy Partners  (25,500) — — 
Proceeds from sale of interest in Rio Grande Pipeline Company, net of transferred cash — Holly Energy Partners 31,865 — — 
Proceeds from sale of crude pipelines and tankage assets 171,000 — —  — 171,000 — 
Proceeds from sale of HPI 5,958 — — 
Net proceeds from sale of Montana Refinery — — 48,872 
Proceeds from sale of Holly Petroleum, Inc. — 5,958 — 
Increase in cash due to consolidation of Holly Energy Partners 7,295 — —  — 7,295 — 
Purchases of marketable securities  (769,142)  (641,144)  (211,972)  (175,892)  (769,142)  (641,144)
Sales and maturities of marketable securities 945,461 509,345 319,334  230,281 945,461 509,345 
Investment in Holly Energy Partners  (290) — —  —  (290) — 
              
Net cash provided by (used for) investing activities
  (57,777)  (293,057) 35,805 
Net cash used for investing activities
  (534,603)  (57,777)  (293,057)
  
Cash flows from financing activities:
  
Net borrowings under credit agreement — Holly Energy Partners 29,000 — — 
Proceeds from issuance of senior notes — Holly Corporation 287,925 — — 
Proceeds from issuance of common units — Holly Energy Partners 133,035 — — 
Borrowings under credit agreement — Holly Corporation 94,000 — — 
Repayments under credit agreement — Holly Corporation  (94,000) — — 
Borrowings under credit agreement — Holly Energy Partners 239,000 114,000 — 
Repayments under credit agreement — Holly Energy Partners  (233,000)  (85,000) — 
Proceeds from Plains financing transaction 40,000 — — 
Deferred financing costs  (913) — —   (8,842)  (913) — 
Purchase of treasury stock  (151,106)  (207,196)  (175,394)  (1,214)  (151,106)  (207,196)
Contribution from joint venture partner 17,000 8,333 —  15,150 17,000 8,333 
Dividends  (29,064)  (23,208)  (15,002)  (30,123)  (29,064)  (23,208)
Distributions to minority interests  (22,098) — — 
Distributions to noncontrolling interest  (33,200)  (22,098) — 
Issuance of common stock upon exercise of options 1,005 2,288 2,645  134 1,005 2,288 
Excess tax benefit from equity based compensation 5,694 30,355 11,816 
Purchase of units for restricted grants — Holly Energy Partners  (795) — — 
Excess tax (expense) benefit from equity based compensation  (1,209) 5,694 30,355 
Other  (807)  (795) — 
              
Net cash used for financing activities
  (151,277)  (189,428)  (175,935)
Net cash provided by (used for) financing activities
 406,849  (151,277)  (189,428)
  
Cash and cash equivalents:
  
  
Increase (decrease) for the period
  (53,564)  (59,748) 105,053  83,791  (53,564)  (59,748)
Beginning of period 94,369 154,117 49,064   40,805(1) 94,369 154,117 
              
End of period
 $40,805 $94,369 $154,117  $124,596 $40,805(1) $94,369 
              
 
(1) Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008.
(1) Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008.
 
 
Supplemental disclosure of cash flow information:
 
Cash paid during the period for 
Interest $39,995 $14,346 $818 
Income taxes $19,344 $21,084 $139,400 
See accompanying notes.

-67-

-78-

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)
                                       
 Accumulated    Holly Corporation Stockholders’ Equity 
 Other Total  Accumulated     
 Common Additional Retained Comprehensive Treasury Stockholders’  Other Non-   
 Stock Capital Earnings Income (Loss) Stock Equity  Common Additional Retained Comprehensive Treasury controlling   
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)
              Stock Capital Earnings Income (Loss) Stock Interest Total Equity 
  
Balance at December 31, 2006
 $718 $66,500 $745,994 $(11,358) $(335,760) $466,094  $718 $66,500 $745,994 $(11,358) $(335,760) $— $466,094 
Net income — — 334,128 — — 334,128  — — 334,128 — — — 334,128 
Dividends — —  (25,148) — —  (25,148) — —  (25,148) — — —  (25,148)
Other comprehensive loss — — —  (7,718) —  (7,718) — — —  (7,718) — —  (7,718)
Contribution from joint venture partner — — — — — 8,333 8,333 
Issuance of common stock upon exercise of stock options 11 2,277 — — — 2,288  11 2,277 — — — — 2,288 
Tax benefit from stock options — 26,017 — — — 26,017  — 26,017 — — — — 26,017 
Issuance of restricted stock, net of forfeitures 4 9,993 — — — 9,997  4 9,993 — — — — 9,997 
Other equity based compensation — 4,338 — — — 4,338  — 4,338 — — — — 4,338 
Purchase of treasury stock — — — —  (216,202)  (216,202) — — — —  (216,202) —  (216,202)
                            
  
Balance at December 31, 2007
 $733 $109,125 $1,054,974 $(19,076) $(551,962) $593,794  $733 $109,125 $1,054,974 $(19,076) $(551,962) $8,333 $602,127 
Reconsolidation of Holly Energy Partners (March 1, 2008) — — — — — 389,184 389,184 
Net income — — 120,558 — — 120,558  — — 120,558 — — 6,078 126,636 
Dividends — —  (30,144) — —  (30,144) — —  (30,144) — — —  (30,144)
Distributions to noncontrolling interest holders — — — — —  (22,098)  (22,098)
Other comprehensive loss — — —  (16,005) —  (16,005) — — —  (16,005) —  (7,079)  (23,084)
Contribution from joint venture partner — — — — — 18,500 18,500 
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 — — — 1,732 4,062 
Purchase of units for restricted grants — — — — —  (795)  (795)
Purchase of treasury stock — — — —  (138,838) —  (138,838)
Other — — — — — 937 937 
               
 
Balance at December 31, 2008
 $735 $121,298 $1,145,388 $(35,081) $(690,800) $394,792 $936,332 
Net income — — 19,533 — — 33,736 53,269 
Dividends — —  (30,580) — — —  (30,580)
Distributions to noncontrolling interest holders — — — — —  (33,200)  (33,200)
Elimination of noncontrolling interest upon HEP’s sale of Rio Grande Pipeline Company — — — — —  (8,718)  (8,718)
Other comprehensive income — — — 9,381 — 2,021 11,402 
Issuance of common shares 28 73,972 — — — — 74,000 
Issuance of HEP common units, net of issuing costs — — — — — 186,801 186,801 
Contribution from joint venture partner — — — — — 13,650 13,650 
Issuance of common stock upon exercise of stock options 2 1,003 — — — 1,005  1 134 — — — — 135 
Tax benefit from stock options — 3,364 — — — 3,364  — 371 — — — — 371 
Issuance of restricted stock, net of forfeitures — 5,476 — — — 5,476  — 5,270 — — — — 5,270 
Other equity based compensation — 2,330 — — — 2,330  —  (5,480) — — 6,083 699 1,302 
Purchase of treasury stock — — — —  (138,838)  (138,838) — — — —  (1,214) —  (1,214)
Other — — — — —  (1,039)  (1,039)
                            
  
Balance at December 31, 2008
 $735 $121,298 $1,145,388 $(35,081) $(690,800) $541,540 
Balance at December 31, 2009
 $764 $195,565 $1,134,341 $(25,700) $(685,931) $588,742 $1,207,781 
                            
See accompanying notes.

-68-

-79-

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)
            
             Years Ended December 31, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  
Net income
 $120,558 $334,128 $266,566  $53,269 $126,636 $334,128 
  
Other comprehensive income (loss):  
  
Securities available-for-sale:  
Unrealized gain (loss) on available-for-sale securities 1,146 1,857  (777) 173 1,146 1,857 
Reclassification adjustment to net income on sale of securities  (1,315)  (78)  (131) 236  (1,315)  (78)
              
Total unrealized gain (loss) on available-for-sale securities  (169) 1,779  (908) 409  (169) 1,779 
  
Retirement medical obligation adjustment 1,433  (5,038) —  742 1,433  (5,038)
Minimum pension liability adjustment  (21,572)  (9,373) 5,542  12,497  (21,572)  (9,373)
  
Other comprehensive loss of Holly Energy Partners:  
Change in fair value of cash flow hedge  (12,967) — —  3,726  (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  17,374  (33,275)  (12,632)
  
Income tax expense (benefit)  (10,191)  (4,914) 1,803  5,972  (10,191)  (4,914)
              
  
Other comprehensive income (loss)  (16,005)  (7,718) 2,831  11,402  (23,084)  (7,718)
              
  
Total comprehensive income
 $104,553 $326,410 $269,397  64,671 103,552 326,410 
        
Less noncontrolling interest in comprehensive income (loss) 35,757 (1,001) — 
       
 
Comprehensive income attributable to Holly Corporation stockholders
 $28,914 $104,553 $326,410 
       
See accompanying notes.

-69-

-80-

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, jet fuel, specialty lubricant products, and jet fuel.specialty and modified asphalt. 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. Our refinery located in Tulsa, Oklahoma (the “Tulsa Refinery”) is comprised of two facilities, the Tulsa Refinery west and east facilities. See Note 2 for additional information on the Tulsa Refinery acquired in 2009.
At December 31, 2008,2009, we owned a 46%34% interest in Holly Energy Partners, L.P. (“HEP”)HEP, a consolidated subsidiary, 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 truckloading rack facilities at each of our three refineries, a refined products tank farm facility and on-site crude oil tankage at both our Navajo and Woods Cross Refineries andRefineries. Additionally, HEP owns a 70%25% interest in Rio GrandeSLC Pipeline LLC (“SLC Pipeline”), a new 95-mile intrastate pipeline system that serves refiners in the Salt Lake City area.
On June 1, 2009, we acquired an 85,000 BPSD refinery in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate of Sunoco, Inc. (“Sunoco”). On December 1, 2009, we acquired a 75,000 BSPD refinery that is also located in Tulsa, Oklahoma (the “Tulsa Refinery east facility”) from an affiliate of Sinclair Oil Company (“Rio Grande”Sinclair”). We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BSPD. See Note 2 for additional information on our 2009 Tulsa Refinery facility acquisitions.
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$6 million, resulting in a gain of $6.0$6 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.

-81-

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.
These consolidated financial statements reflect management’s evaluation of subsequent events through the time of our filing of this annual report on Form 10-K on February 26, 2010.
Reclassifications: There have been certain reclassifications to our December 31, 2008 deferred income tax information under Note 13, “Income Taxes” to conform to current year presentation.
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.

-70-

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, 2009, 2008 2007 and 2006.2007.

-71-

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.

-82-

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, 2008,2009, we have an asset retirement obligation of $1.3$7.2 million, which is included in “Other long-term liabilities” in our consolidated balance sheets. This includes $5.8 million in asset retirement obligations acquired in connection with our Tulsa Refinery facility acquisitions (see Note 2). Accretion expense was insignificant for the years ended December 31, 2009, 2008 and 2007.
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.
As of December 31, 2009, our goodwill balance was $81.6 million. We reconsolidatedrecorded $32.5 million in goodwill due to our reconsolidation of HEP oneffective March 1, 2008 and as a result,2008. Additionally, HEP recorded $27.5$49.1 million in goodwill. Additionally,goodwill related to its acquisition of certain logistics and storage assets from Sinclair in December 2009 (see Note 3). Based on our impairment assessment as of December 31, 2009, we determined that the fair value of the reporting unit’s goodwill exceeded the carrying value and therefore no impairment has occurred.
In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement havingthat currently generates minimum annual cash inflows of $21.7 and has 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$2 million. At December 31, 2008,2009, the balance of this transportation agreement was $52.5$50.3 million, net of accumulated amortization of $1.5$9.7 million, which is included in “Intangible and Others” in our consolidated balance sheets. Amortization expense
The transportation agreement was evaluated for the year endedimpairment as of December 31, 20082009. Based on the evaluation, it was $1.5 million, representing amortization from March 1, 2008 (datedetermined that projected cash flows to be received under the agreement substantially exceeded the carrying balance of reconsolidation) through December 31, 2008.the agreement.
NoThere were no impairments of intangiblesintangible assets or goodwill were recorded during the years ended December 31, 2009, 2008 2007 and 2006.2007.
Variable Interest Entity:HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standard Board (“FASB”) Interpretation (“FIN”) No. 46(R).GAAP. 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 GAAP, HEP’s acquisition of the provisions of FIN No. 46(R), HEP’s purchase of certain pipelinesCrude Pipelines and tankage assets from usTankage Assets (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 consolidated financial statements include the consolidated results of HEP. Amounts allocatedAdditionally, HEP’s 2009 asset acquisitions and its November and May 2009 equity offerings qualified as reconsideration events whereby we determined that HEP continues to qualify as a VIE and we remain HEP’s minority interest holders are recorded to minority interest.primary beneficiary.
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 wherein which we have an ownership interest of greater than 50% and use the equity method of accounting for investments in which we have a 50% or less ownership interest. As of December 31, 2008 we have no investments

-83-

In March 2009, HEP acquired a 25% joint venture interest in joint venturesthe SLC Pipeline that we accountis accounted for using the equity method of accounting. As of December 31, 2009, HEP’s underlying equity in the SLC Pipeline was $63 million compared to its recorded investment balance of $25.9 million, a difference of $37.1 million. This is attributable to the difference between HEP’s contributed capital and its allocated equity at formation of the SLC Pipeline. This difference is being amortized as an adjustment to HEP’s pro-rata share of earnings.
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 11,12, Debt for additional information on HEP’s interest rate swap and hedging activities.

-72-

Noncontrolling Interest:Accounting standards became effective January 1, 2009 that change the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. As a result, all previous references to “minority interest” in our consolidated financial statements have been replaced with “noncontrolling interest.” Therefore, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to 2009, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our consolidated financial statements. We have adopted these standards on a retrospective basis. While this presentation differs from previous requirements under GAAP, it did not affect our net income and equity attributable to Holly Corporation stockholders.

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. Such estimates require judgment with respect to costs, timeframe and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. 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.

-84-

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 InterestsIn June 2009, new accounting standards were issued that replace the previous quantitative-based risk and rewards calculation provided under GAAP with a qualitative approach in Consolidated Financial Statements —determining whether an Amendmententity is the primary beneficiary of Accounting Research Bulletin No. 51”
In December 2007,a VIE. Additionally, these standards require an entity to assess on an ongoing basis whether it is the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendmentprimary beneficiary 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 deconsolidationVIE and requires a parent

-73-

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 theenhances disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies relatedwith respect 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 isinvolvement in a VIE. These standards are 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, 20092010 and will not have a material impact on our financial condition, results of operations and cash flows.
NOTE 2: Discontinued OperationsTulsa Refinery Acquisition
On March 31, 2006June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold the Montana Refinery to Connacher. The net cash proceeds we received on the salean affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the Montanacrude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities that were acquired as part of the refinery assets for $40 million. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing transaction (see Note 12).
On December 1, 2009, we acquired the Tulsa Refinery amounted to $48.9east facility, a 75,000 BPSD refinery from Sinclair also located in Tulsa, Oklahoma for $183.3 million, netincluding crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of transaction fees$109.3 million in cash and expenses.2,789,155 shares of our common stock having a value of $74 million. Additionally, we received 1,000,000 shareswill reimburse Sinclair approximately $8 million upon their satisfactory completion of Connacher common stock valuedcertain environmental projects at $4.3 million at March 31, 2006. the refinery. The refinery also produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are integrating the operations of both Tulsa refinery facilities. This will result in the Tulsa Refinery having an integrated crude processing rate of 125,000 BPSD.
In accounting for the sale,these combined acquisitions, we recorded a pre-tax gain$20.6 million in materials and supplies, $139.2 million in crude oil and refined products inventory, $203.8 million in property, plants and equipment, $8.2 million in prepayments and other, $6.3 million in accrued liabilities and $24.4 million in other long-term liabilities. The acquired liabilities primarily relate to environmental and asset retirement obligations. These amounts are based on management’s preliminary fair value estimates and are subject to change. Additionally, we incurred $3.1 million in costs directly related to these acquisitions that were expensed as acquisition costs.

-85-

For the period from June 1, 2009 (commencement date of $22.3 million. The Montanaour Tulsa Refinery assets disposedoperations) through December 31, 2009, our Tulsa Refinery generated revenues of had$1.1 billion and a net book value at March 31, 2006loss of $13.7 million$17.7 million. We have not provided disclosure of pro forma revenues and earnings as if the Tulsa Refinery had been operating as a part of our refining business during all periods presented in these financial statements. Pro forma financial information specific to the Tulsa Refinery operations 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 occurredperiods prior to our acquisition is not available in GAAP form. The compilation of such financial information would entail an extremely manual process of “unwinding” significant volumes of intra-company transactions and obtaining a comprehensive understanding of accounting policies as well as estimates employed by both Sunoco and Sinclair with respect to items including, but not limited to, inventory and depreciation. We would then need to recast historical financial information to reflect our own estimates and accounting policies. Furthermore, our operating plan with respect to these facilities is distinctly different from the sale. Aspre-acquisition operations of December 31, 2008,these assets as we had an accrualare fully integrating the operations of $1.8 million relatedboth facilities into a single refinery having a reduced integrated crude processing rate of 125,000 BPSD rather than as two distinct facilities. Therefore, we do not believe that it would be practical to such environmental liabilities which is included inproduce this information, nor do we believe it would be representative or comparable with respect to our environmental liability accrual as discussed in Note 10.future operating results.
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 haveAt December 31, 2009, we held 7,290,000 common units of HEP, representing a 46%34% ownership interest in HEP, including our 2% general partner interest. In August 2009, all of the conditions necessary to end the subordination period of our HEP subordinated units were met and the units were converted into 7,000,000 HEP common units.

-74-

HEP is a variable interest entity as defined under FIN No. 46R. Under the provisions of FIN No. 46R,GAAP. 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. As a result, our consolidated financial statements include the results of HEP. Additionally, HEP’s 2009 asset acquisitions and its November and May 2009 equity offerings (discussed below) qualified as reconsideration events whereby we determined that HEP continues to qualify as a VIE and we remain HEP’s primary beneficiary.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, HEP acquired certain logistics and storage assets from an affiliate of Sinclair for $79.2 million consisting of storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at Sinclair’s refinery located in Tulsa, Oklahoma. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million. Concurrent with this transaction we entered into a 15-year pipeline, tankage and loading rack throughput agreement with HEP (the “HEP PTTA”), whereby we agreed to transport, throughput and load volumes of product via HEP’s Tulsa logistics and storage assets that will initially result in minimum annual payments to HEP of $13.8 million.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma (the “Centurion Pipeline”) and a 37-mile, 8-inch crude oil pipeline that connects HEP’s New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).
The Roadrunner Pipeline provides our Navajo Refinery with direct access to a wide variety of crude oils available at Cushing, Oklahoma. In connection with this transaction, we entered into a 15-year pipeline agreement with HEP, (the “HEP RPA”), whereby we agreed to transport volumes of crude oil on HEP’s Roadrunner Pipeline that will initially result in minimum annual payments to HEP of $9.2 million.
The Beeson Pipeline operates as a component of HEP’s crude pipeline system and provides us with added flexibility to move crude oil from HEP’s crude oil gathering system to our Navajo Refinery Lovington facility for processing.

-86-

Tulsa Loading Racks Transaction
On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa Refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa Refinery onto rail cars and/or tanker trucks.
In connection with this transaction, we entered into a 15-year equipment and throughput agreement with HEP, (the “HEP ETA”), whereby we agreed to throughput a minimum volume of products via HEP’s Tulsa loading racks that will initially result in minimum annual payments to HEP of $2.7 million.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million. The pipeline runs 65 miles from our Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico. This pipeline was placed in service effective June 1, 2009 and operates as a component of HEP’s intermediate pipeline system that services our Navajo Refinery.
In connection with this transaction, we agreed to amend our intermediate pipeline agreement with HEP (the “HEP IPA”). As a result, the term of the HEP IPA was extended by an additional four years and now expires in June 2024. Additionally, our minimum commitment under the HEP IPA was increased and currently, results in minimum annual payments to HEP of $20.7 million.
Since HEP is a consolidated subsidiary, our transactions with HEP including fees paid under our transportation agreements with HEP are eliminated and have no impact on our consolidated financial statements.
SLC Pipeline Joint Venture Interest
On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. The SLC Pipeline commenced operations effective March 2009 and allows various refineries 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 flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. HEP’s capitalized joint venture contribution was $25.5 million.
Rio Grande Pipeline Sale
On December 1, 2009 HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.
In accounting for the sale, HEP recorded a gain of $14.5 million. The net asset balance of Rio Grande at December 1, 2009, was $20.5 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net, $2.2 million in accounts payable and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.
The following table provides income statement information related to discontinued operations:
             
  Years Ended December 31, 
  2009  2008  2007 
  (In thousands) 
Income from discontinued operations before income taxes $5,367  $3,716  $— 
Income tax expense  (942)  (798)  — 
          
Income from discontinued operations, net  4,425   2,918   — 
             
Gain on sale of discontinued operations before income taxes  14,479   —   — 
Income tax expense  (1,978)  —   — 
          
Gain on sale of discontinued operations, net  12,501   —   — 
          
             
Income from discontinued operations, net $16,926  $2,918  $— 
          

-87-

2008 Crude Pipelines and Tankage Transaction
On February 29, 2008, we closed on the sale of the Crude Pipelines and Tankage Assets to HEP for $180.0$180 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$171 million in cash and 217,497 HEP common units having a value of $9.0$9 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$86.5 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $338.5 million, an increase in deferred income taxes of $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.
Transportation Agreements
HEP serves our refineries in New Mexico, Utah and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements.
In connection with our 2009 asset transfers to HEP, as described above, we entered into three new 15-year transportation agreements with HEP, each expiring in 2024.
In addition we have an agreement that relates to the pipelines and terminals contributed to HEP by us at the time of their initial public offering in 2004 and expires in 2019 (the “HEP PTA”). We also have the HEP IPA that relates to the intermediate pipelines sold to HEP in 2005 and in June 2009 and expires in 2024 and an agreement that relates to the Crude Pipelines and Tankage Assets sold to HEP also discussed above that expires in February 2023 (the “HEP CPTA”).
Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP’s pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change based upon 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 based upon the percentage change in PPI or Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the HEP IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following the July 1, 2009 PPI rate adjustments, these agreements, including our new 2009 agreements with HEP, will result in minimum payments to HEP of $118.5 million for the twelve months ending June 30, 2010.
Additionally, in February 2010, we entered into a pipeline systems operating agreement with HEP expiring in 2014 (the “HEP Pipeline Operating Agreement”). Under the HEP Pipeline Operating Agreement, effective December 1, 2009, HEP will operate certain of our tankage, pipelines, asphalt racks and terminal buildings for an annual management fee of $1.3 million.

-88-

HEP Equity Offerings
In November 2009, HEP closed on a public offering of 2,185,000 of its common units including 285,000 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s December 1, 2009 asset acquisitions, to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
Additionally in May 2009, HEP closed a public offering of 2,192,400 of its common units including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million were used to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
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 CPTAour long-term transportation agreements and the Omnibus Agreement.our omnibus agreement with HEP. Effective March 1, 2008, we reconsolidated HEP. As a result, our financial statements include the consolidated results of

-75-

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 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 million for the year ended December 31, 2007, respectively, for general and administrative services under an omnibus agreement that we have with HEP that 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 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: Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-tem maturity of these instruments.
Our debt consists of outstanding principal under our long-term senior notes and HEP’s revolving credit agreement and long-term senior notes. The $206 million carrying amount of outstanding debt under HEP’s Credit Agreement approximates fair value as interest rates are reset frequently using current rates. The estimated fair value of the Holly Senior Notes was $318 million and the fair value of the HEP Senior Notes was $177.6 million at December 31, 2009. This fair value estimate is based on market quotes provided from a third-party bank. See Note 12 for additional information on these instruments.
Fair Value Measurements
Fair value measurements are derived using inputs, assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:
(Level 1) Quoted prices in active markets for identical assets or liabilities.
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.
(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

-89-

•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.
Our investments in marketable securities are measured at fair value using quoted market prices, a Level 1 input. See Note 7 for additional information on our investments in marketable securities, including fair value measurements.
We have interest rate swaps that are measured at fair value on a recurring basis using Level 2 inputs. With respect to these instruments, fair value is 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. Our measurements are computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input. See Note 12 for additional information on our interest rate swaps, including fair value measurements.
NOTE 4:5: 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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (In thousands, except per share data) 
 (In thousands, except per share data)  
Income from continuing operations $120,558 $334,128 $246,898  $15,209 $119,206 $334,128 
       
  
Average number of shares of common stock outstanding 50,202 54,852 56,976  50,418 50,202 54,852 
Effect of dilutive stock options, variable restricted shares and performance share units 347 998 1,234  185 347 998 
              
Average number of shares of common stock outstanding assuming dilution 50,549 55,850 58,210  50,603 50,549 55,850 
              
  
Basic earnings per share from continuing operations $2.40 $6.09 $4.33  $0.30 $2.37 $6.09 
  
Diluted earnings per share from continuing operations $2.38 $5.98 $4.24  $0.30 $2.36 $5.98 
NOTE 5:6: Stock-Based Compensation
On December 31, 2008,2009, 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 $6.8 million, $7.6 million $10.8 million and $21.2$10.8 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $2.6 million, $2.9 million $4.2 million and $7.6$4.2 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, 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, 2,407,1722009, 1,932,278 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.
Additionally, HEP maintains share-based compensation plans for HEP directors and select Holly Logistic Services, L.L.C. executives and employees. Compensation cost attributable to HEP’s share-based compensation plans for the year ended December 31, 2009 and 2008 was $1.2 million and $1.7 million, respectively

-76-

-90-

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, 20082009 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 
             
                 
          Weighted-    
      Weighted  Average  Aggregate 
      Average  Remaining  Intrinsic 
      Exercise  Contractual  Value 
Options Shares  Price  Term  ($000) 
                 
Outstanding at January 1, 2009  85,200  $2.98         
Exercised  (45,000)  2.98         
                
Outstanding and exercisable at December 31, 2009  40,200  $2.98   1.2  $911 
             
The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007, and 2006, was $0.9 million, $8.6 million $68.0and $68 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, 2009, 2008 and 2007, and 2006, was $1.0$.1 million, $2.3$1 million and $2.6$2.3 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $0.4 million, $3.4 million $26.0 million and $12.0$26 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, 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, 20082009 is presented below:
                        
 Weighted-    Weighted Aggregate 
 Average    Average Intrinsic 
 Grant-Date Aggregate Intrinsic  Grant-Date Value 
Restricted Stock Grants Fair Value Value ($000)  Grants Fair Value ($000) 
Outstanding at January 1, 2008 (non-vested) 298,565 $27.22 
 
Outstanding at January 1, 2009 (non-vested) 235,310 $35.86 
Vesting and transfer of ownership to recipients  (138,648) $23.58   (133,616) 26.59 
Granted 86,409 $45.91  186,801 23.16 
Forfeited  (11,016) $34.87   (4,045) 40.06 
      
Outstanding at December 31, 2008 (non-vested) 235,310 $35.86 $4,290 
Outstanding at December 31, 2009 (non-vested) 284,450 $31.82 $7,290 
              

-77-

The total fair value of restricted stock vested and transferred to recipients during the years ended December 31, 2009, 2008 and 2007 and 2006 was $3.4 million, $2.5 million $12.9 million and $5.5$12.9 million, respectively. As of December 31, 2008,2009, there was $2.0$1.8 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 1.21.3 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.

-91-

During the year ended December 31, 2008,2009, we granted 60,605122,555 performance share units with a fair value based on our grant date closing stock price of $47.47.$22.94. All shares were granted during the first quarter of 20082009 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, 2008,2009, estimated share payouts for outstanding non-vested performance share unit awards ranged from 80%130% to 156%170%.
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, 20082009 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 
             
Performance Share UnitsGrants
Outstanding at January 1, 2009 (non-vested)169,669
Vesting and transfer of ownership to recipients(72,059)
Granted122,555
Forfeited(4,995)
Outstanding at December 31, 2009 (non-vested)215,170
For the year ended December 31, 20082009 we paid $6.0 million and issued 84,948110,971 shares of our common stock (representing a 200% share payout) having a fair value of $2.7$2.2 million related to vested performance share units.units, representing a 154% payout. Based on the weighted average grant date fair value of $42.50$35.07 there was $5.2$3.5 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 1.31.7 years.
NOTE 6:7: 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 Refineryrefinery in 2006.

-78-

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, 2008:2009:
                 
  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 
             
             
  Available-for-Sale Securities 
          Estimated 
      Gross  Fair Value 
  Amortized  Unrealized  (Net Carrying 
  Cost  Gain  Amount) 
  (In thousands) 
             
Equity securities $604  $619  $1,223 
          

-92-

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, 2007:2008:
                            
 Available-for-Sale Securities  Available-for-Sale Securities 
 Estimated  Estimated 
 Gross Fair Value  Gross Recognized Fair Value 
 Amortized Unrealized (Net Carrying  Amortized Unrealized Impairment (Net Carrying 
 Cost Gain (Loss) Amount)  Cost Gain Loss Amount) 
 (In thousands)  (In thousands) 
States and political subdivisions $230,709 $866 $231,575  $54,389 $210 $— $54,599 
Equity securities 4,328  (488) 3,840  4,328 —  (3,724) 604 
                
Total marketable securities $235,037 $378 $235,415  $58,717 $210 $(3,724) $55,203 
                
For the yearyears ended December 31, 2007,2009 and 2008, we received a total of $509.3$230.3 million and $945.5 million, respectively, related to sales and maturities of our investments in marketable debt securities.
NOTE 7:8: 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.

-79-

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 
       
         
  December 31, 
  2009  2008 
  (In thousands) 
         
Crude oil $60,874  $21,446 
Other raw materials and unfinished products(1)
  42,783   2,640 
Finished products(2)
  155,925   83,725 
Process chemicals(3)
  22,823   3,800 
Repairs and maintenance supplies and other  21,108   14,124 
       
Total inventory $303,513  $125,735 
       
(1) Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.
 
(2) Finished products include gasolines, jet fuels, diesels, lubricants, 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$207 million and $199.4$33 million at December 31, 2009 and 2008, and 2007, respectively. WeFor the year ended December 31, 2009, we recognized a reduction in$8.4 million charge to cost of products soldsold. This charge was due to the liquidation of $8.4 million forcertain LIFO inventory quantities that were carried at higher costs as compared to 2009 LIFO inventory acquisition costs. For the year ended December 31, 2008, andwe recognized a charge of $0.8an $8.4 million toreduction in cost of products sold for the year ended December 31, 2007. The 2008sold. This 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 the2008 year.

-93-

NOTE 8:9: Properties, Plants and Equipment
        
         December 31, 
 December 31,  2009 2008 
 2008 2007  (In thousands) 
 (In thousands)  
Land, buildings and improvements $54,529 $24,340  $73,973 $54,529 
Refining facilities 493,706 478,445  981,594 493,706 
Pipelines and terminals 338,558 68,709  478,522 338,558 
Transportation vehicles 19,313 13,564  20,760 19,313 
Oil and gas exploration and development — 2,917 
Other fixed assets 50,187 43,534  80,546 50,187 
Construction in progress 553,408 171,311  366,460 553,408 
          
 1,509,701 802,820  2,001,855 1,509,701 
Accumulated depreciation  (304,379)  (271,970)  (371,885)  (304,379)
          
 $1,205,322 $530,850  $1,629,970 $1,205,322 
          
During the yearyears ended December 31, 2009 and 2008 $1.0we capitalized $3.2 million and $1 million, respectively, in interest attributable to HEP’s construction projects was capitalized. We did not capitalize any interest in 2007.projects.
Depreciation expense was $78.4 million, $53.3 million $35.8 million and $30.9$35.8 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, respectively. Depreciation expense for the yearyears ended December 31, 2009 and 2008 includes $25 million and $17.5 million, respectively, of depreciation expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.

-80-

NOTE 9:10: 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 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. Our$275 million, with our share of this cost would be $225.0totaling $206 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per dayBPD 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 dayBPD 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 We expect the project iswill be ready to commence operations in the final stagefall of 2010.
We currently anticipate that all regulatory approvals required to commence the construction of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceedUNEV Pipeline will now be received duringby the end of the second quarter of 2009, we2010. Once such approvals are currently evaluating whether to maintainreceived, construction of the current completionpipeline will take approximately nine months. Under this schedule, for UNEVthe pipeline would become operational during the first quarter of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.2011.
NOTE 10:11: Environmental Costs
Consistent with our accounting policy for environmental remediation costs, we expensed $0.4$4.2 million, $2.3$0.6 million and $5.6$2.3 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheet was $7.3$30.4 million and $8.6$7.3 million at December 31, 20082009 and 2007,2008, respectively, of which $4.2$24.2 million and $5.3$4.2 million, respectively, was classified as other long-term liabilities. These liabilities include $22.3 million of environmental obligations that we assumed in connection with our Tulsa Refinery acquisitions on June 1, 2009 and December 1, 2009. Costs of future expenditures for environmental remediation that are expected to be incurred over the next several years and are not discounted to their present value.

-94-

NOTE 11:12: Debt
Credit Facilities
We have a $370 million senior secured credit agreement expiring in March 2013. In March 2008,April 2009, we entered into ana second amended and restated $175.0$300 million senior secured revolving credit agreement (the “Credit Agreement”) that amendsamended and restatesrestated our previous credit agreement in its entirety with Bank of America, N.A. as administrative agent and lender.one of a syndicate of lenders (the “Holly Credit Agreement”). Additionally, we upsized the credit agreement by $50 million in November 2009 and by an additional $20 million in December 2009 pursuant to the accordion feature. 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 andagreement may be used to fund working capital requirements, capital expenditures, permitted acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2008.2009. At December 31, 2008,2009, we had no outstanding borrowings and letters of credit totaling $2.5$56.3 million and no outstanding borrowings under our credit facility.the Holly Credit Agreement. At that level of usage, the unused commitment under our credit facilitythe Holly Credit Agreement was $172.5$313.7 million at December 31, 2008.2009.
HEP has a $300.0$300 million senior secured revolving credit agreement expiring in August 2011 (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 usedAgreement is available to fund working capital requirements, capital expenditures, acquisitions orand working capital and for other general partnership purposes. At December 31, 2009, HEP had outstanding borrowings totaling $206 million under the HEP Credit Agreement with unused borrowing capacity of $94 million. 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, 20082009 consist of $5.3$2.5 million in cash and cash equivalents, $5.1$7.6 million in trade accounts receivable and other current assets, $354.1$458.5 million in property, plant and equipment, net and $56.1$159 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., theirits 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 theirits 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 $171.0a $171 million aggregate principal amount of borrowings under the HEP Credit Agreement.

-81-

Holly Senior Notes Due 2017

In June 2009, we issued $200 million in aggregate principal amount of Holly Senior Notes. A portion of the $188 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa Refinery west facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the Holly Senior Notes that was used to fund the cash portion of our acquisition of Sinclair’s 75,000 BPD refinery located in Tulsa, Oklahoma.
The $300 million aggregate principal amount of Holly Senior Notes mature on June 15, 2017 and bear interest at 9.875%. The Holly Senior Notes are unsecured and impose certain restrictive covenants, including limitations on Holly’s ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. At any time when the Holly Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Holly Senior Notes.
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., theirits 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 theirits 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$35 million of the principal amount of the HEP Senior Notes.

-95-

Holly Financing Obligation
On October 20, 2009, we sold to Plains a portion of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities located at our Tulsa Refinery east facility. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits with Plains for crude oil purchased by them and delivered to our Tulsa Refinery west facility for storage. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing obligation. As a result, we retained our assets on our books and established a liability representing the $40 million in proceeds received.
The carrying amounts of long-term debt are as follows:
         
  December 31,  December 31, 
  2009  2008 
  (In thousands) 
Holly Senior Notes        
Principal $300,000  $— 
Unamortized discount  (11,549)  — 
       
         
   288,451   — 
Holly Financing Obligation        
Principal  39,809   — 
       
         
Total Holly long-term debt $328,260  $— 
       
         
HEP Credit Agreement $206,000  $200,000 
         
HEP Senior Notes        
Principal  185,000   185,000 
Unamortized discount  (13,593)  (16,223)
Unamortized premium — de-designated fair value hedge  1,791   2,137 
       
   173,198   170,914 
       
Total HEP debt  379,198   370,914 
Less HEP Credit Agreement borrowings classified as short-term debt  —   29,000 
       
         
Total HEP long-term debt $379,198  $341,914 
       
At December 31, 2008,2009, the carrying amountestimated fair values 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 
    
the Holly Senior Notes and the HEP Senior Notes were $318 million and $177.6 million, respectively.
Interest Rate Risk Management
HEP uses interest rate swaps (derivative instruments) to mange its exposure to interest rate risk. As of December 31, 2008,2009, HEP hadhas three interest rate swap contracts.
HEP entered intohas an interest rate swap to hedge theirits exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0$171 million HEP Credit Agreement advance that HEPwas used to finance theirHEP’s purchase of the Crude Pipelines and Tankage Assets from us. This interest rate swap effectively converts their $171.0its $171 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 this2009. This swap contract ismatures in 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.

-96-

HEP designated this interest rate swap as a cash flow hedge. Based on theirits 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$171 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, HEP adjusts theirthe cash flow hedge on a quarterly basis to its fair value on a quarterly basis with a corresponding offsetthe offsetting fair value adjustment 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$171 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008,2009, HEP had no ineffectiveness on theirits cash flow hedge.
HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0$60 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$60 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%1.41% as of December 31, 2008.2009. 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$60 million of theirits hedged

-82-

long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0$60 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$60 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 thisthat 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’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 the offsetting fair value adjustment to interest expense. For the years ended December 31, 2009 and 2008, HEP recognized an increase of $0.2 million and $2.3 million, respectively, in interest expense as a result of fair value adjustments to its interest rate swaps.
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 at December 31, 2009 is as follows:
                           
 Balance Sheet Location of Offsetting Offsetting  Balance Sheet Location of Offsetting Offsetting 
Interest Rate Swaps Location Fair Value Balance Amount  Location Fair Value Balance Amount 
 (In thousands)  (In thousands) 
Asset
      
Fixed-to-variable interest rate swap - - $60 million of 6.25% Senior Notes Long-term debt $(2,195)
Fixed-to-variable interest rate swap —
$60 million of 6.25% HEP Senior Notes		 Other assets $2,294 Long-term debt — HEP $(1,791)(1)
 Other assets $4,079 Interest expense  (1,884)   Equity  (1,942)(2)
        Interest expense  1,439(3)
       
 $4,079 $(4,079)     
        $2,294   $(2,294)
          
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 
Cash flow hedge — $171 million LIBOR based debt Other long-term liabilities $(9,141) Accumulated other comprehensive loss $9,141 
     
Variable-to-fixed interest rate swap — Other long-term liabilities Equity  4,166(2)
$60 million    (2,555) Interest expense  (1,611)
             
 $(17,133) $17,133      
        $(11,696)   $11,696 
         
(1)Represents unamortized balance of dedesignated hedge premium.
(2)Represents prior year charges to interest expense.
(3)Net of amortization of premium attributable to dedesignated hedge.

-97-

We made cash interest payments
On January 29, 2010, HEP received notice from the counterparty that it is exercising its option to cancel the Variable Rate Swap on March 1, 2010, pursuant to the terms of $14.3 million, $0.8 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.swap contract. HEP will receive a cancellation premium of $1.9 million.
NOTE 12:13: Income Taxes
The provision for income taxes from continuing operations is comprised of the following:
                        
 Years Ended December 31,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
 (In thousands)  (In thousands) 
Current  
Federal $27,795 $113,999 $105,469  $(24,876) $27,795 $113,999 
State 4,097 28,246 20,712   (2,266) 4,097 28,246 
Deferred  
Federal 27,727 21,867 9,490  33,269 27,727 21,867 
State 5,207 1,204 932  4,253 5,207 1,204 
              
 $64,826 $165,316 $136,603  $10,380 $64,826 $165,316 
              

-83-

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, 
 Years Ended December 31,  2009 2008 2007 
 2008 2007 2006  (In thousands) 
 (In thousands)  
Tax computed at statutory rate $64,884 $174,805 $134,225  $15,331 $65,711 $174,805 
State income taxes, net of federal tax benefit 7,230 19,478 14,957  1,708 7,322 19,478 
Federal tax credits  (1,896)  (16,078)  (10,776)  (65)  (1,896)  (16,078)
Domestic production activities deduction  (2,380)  (8,670) —  —  (2,380)  (8,670)
Tax exempt interest  (2,772)  (4,200) —   (168)  (2,772)  (4,200)
Discontinued operations (including noncontrolling interest) 7,720 1,820 — 
Noncontrolling interest in continuing operations  (13,123)  (2,739) — 
Other  (240)  (19)  (1,803)  (1,023)  (240)  (19)
              
 $64,826 $165,316 $136,603  $10,380 $64,826 $165,316 
              
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, 20082009 and 20072008 are as follows:
                        
 December 31, 2008  December 31, 2009 
 Assets Liabilities Total  Assets Liabilities Total 
 (In thousands)  (In thousands) 
Deferred taxes  
Accrued employee benefits $7,135 $(29) $7,106  $7,701 $— $7,701 
Accrued postretirement benefits 2,607 286 2,893  1,812 — 1,812 
Accrued environmental costs 1,202 — 1,202  2,339 — 2,339 
Inventory differences 247 489 736  7,951 — 7,951 
Prepayments and other 1,066  (2,297)  (1,231) 2,423  (3,321)  (898)
              
Total current(1)
 12,257  (1,551) 10,706  22,226  (3,321) 18,905 
Properties, plants and equipment (due primarily to tax in excess of book depreciation) —  (122,684)  (122,684) —  (176,889)  (176,889)
Accrued postretirement benefits 14,824 — 14,824  13,488 — 13,488 
Accrued environmental costs 1,591 — 1,591  9,420 — 9,420 
Deferred turnaround costs —  (11,491)  (11,491) —  (18,257)  (18,257)
Investments in HEP 44,557 55 44,612 
Investment in HEP 47,188  (4,507) 42,681 
Other 6,212  (2,555) 3,657  7,512  (2,540) 4,972 
              
Total noncurrent 67,184  (136,675)  (69,491) 77,608  (202,193)  (124,585)
              
Total $79,441 $(138,226) $(58,785) $99,834 $(205,514) $(105,680)
              
             
  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)
          

-98-

             
  December 31, 2008 
  Assets  Liabilities  Total 
  (In thousands) 
Deferred taxes            
Accrued employee benefits $7,135  $(29) $7,106 
Accrued postretirement benefits  2,893   —   2,893 
Accrued environmental costs  1,202   —   1,202 
Inventory differences  736   —   736 
Prepayments and other  1,066   (2,297)  (1,231)
          
Total current(1)
  13,032   (2,326)  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)
Investment in HEP  44,612   —   44,612 
Other  6,212   (2,555)  3,657 
          
Total noncurrent  67,239   (136,730)  (69,491)
          
Total $80,271  $(139,056) $(58,785)
          
(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 $19.3 million in 2009, $21.1 million in 2008 and $139.4 million in 2007 and $142.9 million in 2006.2007.

-84-

The total amount of unrecognized tax benefits as of December 31, 2008,2009, was $4.4$2 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
        
 Liability for  Liability for 
 Unrecognized  Unrecognized 
 Tax Benefits  Tax Benefits 
 (In thousands)  (In thousands) 
Balance at January 1, 2008 $3,539 
Balance at January 1, 2009 $4,350 
Additions based on tax positions related to the current year 960  3 
Additions for tax positions of prior years 479  358 
Reductions for tax positions of prior years  (628)  (2,747)
      
 
Balance at December 31, 2008 $4,350 
Balance at December 31, 2009 $1,964 
      
Included in the unrecognized tax benefits at December 31, 20082009 are $2.5$1.1 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, 2008,2009, we recognized $0.8$1 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 20082009 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 income tax matters for tax years through December 31, 2005 and all state and local income tax matters for fiscaltax 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.

-99-

NOTE 13:14: 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 
          
             
  Years Ended December 31, 
  2009  2008  2007 
             
Common shares outstanding at beginning of year  49,943,220   52,616,169   55,316,615 
Common shares issued to Sinclair in connection with Tulsa Refinery east facility acquisition  2,789,155   —   — 
Issuance of common stock upon exercise of stock options  45,000   406,000   1,085,600 
Issuance of restricted stock, excluding restricted stock with performance feature  154,078   46,943   49,677 
Vesting of performance units  146,664   84,948   151,000 
Vesting of restricted stock with performance feature  49,719   57,572   180,519 
Forfeitures of restricted stock  (1,633)  (2,033)  (23,537)
Purchase of treasury stock(1)
  (59,934)  (3,266,379)  (4,143,705)
          
Common shares outstanding at end of year  53,066,269   49,943,220   52,616,169 
          
(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, 2008,2009, we repurchased 3,228,489did not purchase any shares of common stock, other than shares purchased to provide funds for the payment of payroll and income taxes due at a costthe vesting of $137.1 million or an average of $42.48 per share.restricted shares for certain officers and employees who did not elect to satisfy such taxes by other means. Since inception of our common stock repurchase initiative beginning in May 2005 through December 31, 2008,2009, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.

-85-

During the year ended December 31, 2008,2009, we repurchased at market price from certain executives 55,51559,934 shares of our common stock at a cost of $2.0$1.2 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 14:15: Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) are as follows:
                        
 Tax Expense    Tax Expense   
 Before-Tax (Benefit) After-Tax  Before-Tax (Benefit) After-Tax 
 (In thousands)  (In thousands) 
For the year ended December 31, 2009
 
Unrealized gain on available-for-sale securities $409 $158 $251 
Retirement medical obligation adjustment 742 289 453 
Minimum pension liability adjustment 12,497 4,862 7,635 
Unrealized gain on HEP cash flow hedge 3,726 663 3,063 
       
Other comprehensive income 17,374 5,972 11,402 
Less other comprehensive income attributable to noncontrolling interest 2,021 — 2,021 
       
Other comprehensive income attributable to Holly Corporation stockholders $15,353 $5,972 $9,381 
       
 
For the year ended December 31, 2008
  
Unrealized loss on available-for-sale securities $(169) $(67) $(102)
Retirement medical obligation adjustment 1,433 557 876 
Minimum pension liability adjustment $(21,572) $(8,391) $(13,181)  (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)
Unrealized loss on HEP cash flow hedge  (12,967)  (2,290)  (10,677)
              
Other comprehensive loss $(26,196) $(10,191) $(16,005)  (33,275)  (10,191)  (23,084)
Less other comprehensive loss attributable to noncontrolling interest  (7,079) —  (7,079)
              
Other comprehensive loss attributable to Holly Corporation stockholders $(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 
       

-100-

             
      Tax Expense    
  Before-Tax  (Benefit)  After-Tax 
  (In thousands) 
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 attributable to Holly Corporation stockholders $(12,632) $(4,914) $(7,718)
          
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 sheetour Consolidated Balance Sheets includes:
        
         December 31, 
 December 31,  2009 2008 
 2008 2007  (In thousands) 
 (In thousands)  
Pension obligation adjustment $(29,409) $(16,228) $(21,774) $(29,409)
Retiree medical obligation adjustment  (2,202)  (3,078)  (1,749)  (2,202)
Unrealized gain on securities available-for-sale 128 230  379 128 
Unrealized loss on HEP cash flow hedge, net of minority interest  (3,598) —   (2,556)  (3,598)
          
Accumulated other comprehensive loss $(35,081) $(19,076) $(25,700) $(35,081)
          
NOTE 15:16: Retirement Plans
Retirement Plan:We have a non-contributory defined benefit retirement plan that covers substantially all employees.most of our employees who were hired prior to January 1, 2007. 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.

-86-

The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 20082009 and 2007:2008:
                
 Years Ended December 31,  Years Ended December 31, 
 2008 2007  2009 2008 
 (In thousands)  (In thousands) 
Change in plan’s benefit obligation  
Pension plan’s benefit obligation — beginning of year $72,842 $62,107  $74,488 $72,842 
Service cost 4,229 4,110  4,314 4,229 
Interest cost 4,692 4,075  4,943 4,692 
Benefits paid  (6,188)  (5,806)  (3,726)  (6,188)
Actuarial (gain) loss  (1,087) 8,356  1,151  (1,087)
          
Pension plan’s benefit obligation — end of year 74,488 72,842  81,170 74,488 
  
Change in pension plan assets  
Fair value of plan assets — beginning of year 56,454 50,414  45,342 56,454 
Actual return on plan assets  (19,924) 1,846  12,977  (19,924)
Benefits paid  (6,188)  (5,806)  (3,726)  (6,188)
Employer contributions 15,000 10,000  1,025 15,000 
          
Fair value of plan assets — end of year 45,342 56,454  55,618 45,342 
 
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)
     

-101-

         
  Years Ended December 31, 
  2009  2008 
  (In thousands) 
Funded status        
Under-funded balance $(25,552) $(29,146)
       
         
Amounts recognized in consolidated balance sheets        
Accrued pension liability $(25,552) $(29,146)
       
         
Amounts recognized in accumulated other comprehensive loss        
Actuarial loss $(31,677) $(43,475)
Prior service cost  (2,811)  (3,201)
       
Total $(34,488) $(46,676)
       
The accumulated benefit obligation was $58.7$65 million and $55.4$58.7 million at December 31, 20082009 and 2007,2008, respectively. The measurement dates used for our retirement plan were December 31, 20082009 and 2007.2008.
The weighted average assumptions used to determine end of period benefit obligations:
        
         December 31, 
 December 31, 2009 2008 
 2008 2007 
Discount rate  6.50%  6.40%  6.20%  6.50%
Rate of future compensation increases  4.00%  4.00%  4.00%  4.00%
Net periodic pension expense consisted of the following components:
                        
 Years Ended December 31,  Years Ended December 31, 
 2008 2007 2006  2009 2008 2007 
 (In thousands)  (In thousands) 
Service cost — benefit earned during the year $4,229 $4,110 $4,270  $4,314 $4,229 $4,110 
Interest cost on projected benefit obligations 4,692 4,075 4,133  4,943 4,692 4,075 
Expected return on plan assets  (4,793)  (4,078)  (3,473)  (3,843)  (4,793)  (4,078)
Amortization of prior service cost 390 390 258  390 390 390 
Amortization of net loss 1,218 908 1,042  3,815 1,218 908 
Curtailment loss — — 663 
Settlement loss — — 1,589 
              
Net periodic pension expense $5,736 $5,405 $8,482  $9,619 $5,736 $5,405 
              

-87-

The weighted average assumptions used to determine net periodic benefit expense:
                        
 Years Ended December 31, Years Ended December 31, 
 2008 2007 2006 2009 2008 2007 
 (In thousands) 
Discount rate  6.40%  6.00%  6.05%  6.50%  6.40%  6.00%
Rate of future compensation increases  4.00%  4.00%  4.00%  4.00%  4.00%  4.00%
Expected long-term rate of return on assets  8.50%  8.50%  8.50%  8.50%  8.50%  8.50%
The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 20092010 are as follows:
        
 (In thousands)  (In thousands) 
Actuarial loss $3,984  $2,496 
Prior service cost 390  390 
      
Total $4,374  $2,886 
      

-102-

At year end, our retirement plan assets were allocated as follows:
            
 Percentage of Plan Assets at            
 Year End Percentage of Plan Assets at 
 Target     Target Year End 
 Allocation December 31, December 31, Allocation December 31, December 31, 
Asset Category 2009 2008 2007 2010 2009 2008 
Equity securities  70%  65%  68%  70%  69%  65%
Debt Securities  30%  35%  32%  30%  31%  35%
              
Total  100%  100%  100%  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 $20.0zero and $10 million to the retirement plan in 2009.2010. Benefit payments, which reflect expected future service, are expected to be paid as follows: $4.6 million in 2009; $5.2$5.6 million in 2010; $5.9$6.3 million in 2011; $7.4$7.1 million in 2012, $7.62012; $8 million in 2013 and $50.42013; $7.8 million in 2014-2018.2014 and $55.2 million in 2015-2019.
Retirement Restoration Plan:We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. We expensed $0.7 million, $1.1 million $0.9 million and $0.8$0.9 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, 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, 20082009 and 2007, respectively.2008. As of December 31, 2008,2009, 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$0.4 million in 2010; $0.9$1.2 million in 2011; $0.6$0.5 million in 2012; $1.4$1.7 million in 2013 and $2.92013; $0.5 million in 2014-2018.2014 and $3.2 million in 2015-2019.
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 $5 million, $3.7 million $2.8 million and $1.9$2.8 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, respectively, in connection with these plans.

-88-

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$6.6 million and $7.5$6.6 million at December 31, 20082009 and 2007,2008, 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, 2008,2009, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7$6.6 million.

-103-

NOTE 16:17: Lease Commitments
We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2008,2009, 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  $16,712 
2011 7,483  14,963 
2012 6,453  11,683 
2013 6,382  9,919 
2014 9,360 
Thereafter 22,839  25,125 
      
Total $60,535  $87,762 
      
Rental expense charged to operations was $9.9$11.8 million, $3.2$9.8 million and $2.3$3.2 million for the years ended December 31, 2009, 2008 2007 and 2006,2007, respectively. Rental expense for the yearyears ended December 31, 2009 and 2008 includes $6.6$7.1 million and $6.5 million, respectively, of rental expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.
NOTE 17:18: 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’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.Arizona on SFPP’s East Line. 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 relating to East Line service 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

-89-

November 2010. The CommissionFERC approved the settlement on January 29, 2009. The settlement will reducereduced SFPP’s current rates and requirerequired SFPP to make additional payments to us of approximately $2.0 million.$2.9 million, which was received on May 18, 2009.
On June 2, 2009, SFPP notified us that it would terminate the October 2008 settlement, as provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial rate increases for East Line service to become effective September 1, 2009. We and several other shippers filed protests at the FERC challenging the rate increase and asking FERC to suspend the effectiveness of the increased rates. On August 31, 2009, FERC issued an order suspending the effective date of the rate increase until January 1, 2010, on which date the rate increase was placed into effect, and setting the rate increase for a full evidentiary hearing to be held in 2010. We are not in a position to predict the ultimate outcome of the rate proceeding.

-104-

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.expiring in 2023. 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 21,00043,000 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.years expiring in 2019 through 2024.
Other contractual obligations relate to the transportation of natural gas and feedstocks to our refineries under contracts expiring in 20152016 through 20232024 and various service contracts with expiration dates through 2011.
NOTE 18:19: 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, Refineryand Tulsa Refineries 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.fuel. The petroleum products produced by the Refining segment are primarily marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washingtonthe Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. TheAdditionally, the Refining segment also includes specialty lubricant products produced at our Tulsa Refinery that are marketed throughout North America and are distributed in Central and South America. 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. GAAP. A VIE is 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. 46R,GAAP, HEP’s purchaseacquisition of the Crude Pipelines and Tankage Assets (see Note 3) qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP.whether HEP continued to qualify as a VIE. Following this transaction,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 consolidated financial statements include the results of HEP.
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 oilgathering 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 theirits pipelines, by leasing certain pipeline capacity to Alon USA, Inc., 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%25% interest in Rio Grande which also provides petroleum products transportation services.SLC Pipeline that services refineries in the Salt Lake City, Utah area. 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.operations. 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.

-90-

-105-

                     
              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 
                     
              Consolidations    
          Corporate  and  Consolidated 
  Refining(1)  HEP(2)  and Other  Eliminations  Total 
  (In thousands) 
Year Ended December 31, 2009
                    
Sales and other revenues $4,786,937  $146,561  $2,248  $(101,478) $4,834,268 
Depreciation and amortization $67,347  $24,599  $6,805  $—  $98,751 
Income (loss) from operations $68,397  $70,373  $(57,355) $(1,104) $80,311 
Capital expenditures $266,648  $32,999  $2,904  $—  $302,551 
Total assets $2,142,317  $641,775  $392,007  $(30,160) $3,145,939 
                     
Year Ended December 31, 2008
                    
Sales and other revenues $5,837,449  $94,439  $2,641  $(74,172) $5,860,357 
Depreciation and amortization $40,090  $18,390  $4,515  $—  $62,995 
Income (loss) from operations $210,252  $37,082  $(51,654) $—  $195,680 
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 
(1)The Refining segment reflects the operations of our Tulsa Refinery west and east facilities beginning on our respective acquisition dates of June 1, 2009 and December 1, 2009, respectively.
(2) HEP segment revenues from external customers were $27.6$45.5 million and $19.3 million for the yearyears ended December 31, 2009 and 2008, respectively. The HEP segment reflects the operations of various 2009 asset acquisitions (see Note 3).
NOTE 20: Supplemental Guarantor/Non-Guarantor Financial Information
Our obligations under the Holly Senior Notes have been jointly and severally guaranteed by the substantial majority of our existing and future restricted subsidiaries (“Guarantor Restricted Subsidiaries”). These guarantees are full and unconditional. HEP in which we have a 34% ownership interest and its subsidiaries (collectively, “Non-Guarantor Non-Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed these obligations.
The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of Holly Corporation (the “Parent”), the Guarantor Restricted Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Restricted Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the Non-Guarantor Restricted Subsidiaries are collectively the “Restricted Subsidiaries.”
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.

-106-

Condensed Consolidating Balance Sheet
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
December 31, 2009 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
ASSETS
                                
Current assets:                                
Cash and cash equivalents $127,560  $(12,477) $7,005  $—  $122,088  $2,508  $—  $124,596 
Marketable securities  —   1,223   —   —   1,223   —   —   1,223 
Accounts receivable  973   759,140   —   —   760,113   18,767   (16,425)  762,455 
Intercompany accounts receivable (payable)  (1,134,296)  817,647   316,649   —   —   —   —   — 
Inventories  —   303,348   —   —   303,348   165   —   303,513 
Income taxes receivable  38,071   1   —   —   38,072   —   —   38,072 
Prepayments and other assets  24,940   29,018   —   —   53,958   574   (3,575)  50,957 
Current assets of discontinued operations  —   —   —   —   —   2,195   —   2,195 
                         
Total current assets  (942,752)  1,897,900   323,654   —   1,278,802   24,209   (20,000)  1,283,011 
                                 
Properties and equipment, net  21,918   1,005,422   155,413   —   1,182,753   458,521   (11,304)  1,629,970 
Investment in subsidiaries  2,010,510   435,970   (314,973)  (2,131,507)  —   —   —   — 
Intangibles and other assets  8,752   64,017   —   —   72,769   159,045   1,144   232,958 
                         
Total assets $1,098,428  $3,403,309  $164,094  $(2,131,507) $2,534,324  $641,775  $(30,160) $3,145,939 
                         
                                 
LIABILITIES AND EQUITY
                                
Current liabilities:                                
Accounts payable $8,968  $974,177  $2,224  $—  $985,369  $6,211  $(16,425) $975,155 
Accrued liabilities  23,752   15,477   709   —   39,938   13,594   (3,575)  49,957 
Other liabilities  —   —   —   —   —   —   —   — 
                         
Total current liabilities  32,720   989,654   2,933   —   1,025,307   19,805   (20,000)  1,025,112 
                                 
Long-term debt  288,451   39,809   —   —   328,260   379,198   —   707,458 
Non-current liabilities  37,859   48,137   —   —   85,996   12,349   (17,342)  81,003 
Deferred income taxes  119,127   229   278   —   119,634   —   4,951   124,585 
Distributions in excess of inv in HEP  —   314,970   —   —   314,970   —   (314,970)  — 
Equity — Holly Corporation  620,271   2,010,510   160,883   (2,171,393)  620,271   230,423   (231,655)  619,039 
Equity — Noncontrolling interest  —   —   —   39,886   39,886   —   548,856   588,742 
                         
Total liabilities and equity $1,098,428  $3,403,309  $164,094  $(2,131,507) $2,534,324  $641,775  $(30,160) $3,145,939 
                         

-107-

Condensed Consolidating Balance Sheet
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
December 31, 2008 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
ASSETS
                                
Current assets:                                
Cash and cash equivalents $33,316  $(1,182) $3,402  $—  $35,536  $3,708  $—  $39,244 
Marketable securities  48,590   604   —   —   49,194   —   —   49,194 
Accounts receivable  1,734   283,480   1,524   —   286,738   13,332   (11,451)  288,619 
Intercompany accounts receivable (payable)  (1,419,212)  1,134,118   285,094   —   —   —   —   — 
Inventories  —   125,613   —   —   125,613   122   —   125,735 
Income taxes receivable  6,350   —   —   —   6,350   —   —   6,350 
Prepayments and other assets  13,814   6,842   —   —   20,656   471   (2,352)  18,775 
Current assets of discontinued operations  —   —   —   —   —   2,706   —   2,706 
                         
Total current assets  (1,315,408)  1,549,475   290,020   —   524,087   20,339   (13,803)  530,623 
                                 
Properties and equipment, net  22,997   718,575   109,660   —   851,232   321,692   —   1,172,924 
Marketable securities (long-term)  6,009   —   —   —   6,009   —   —   6,009 
Investment in subsidiaries  1,911,613   371,964   (321,003)  (1,962,574)  —   —   —   — 
Intangibles and other assets  —   48,651   —   —   48,651   83,620   —   132,271 
Non-current assets of discontinued operations  —   —   —   —   —   32,398   —   32,398 
                         
Total assets $625,211  $2,688,665  $78,677  $(1,962,574) $1,429,979  $458,049  $(13,803) $1,874,225 
                         
                                 
LIABILITIES AND EQUITY
                                
Current liabilities:                                
Accounts payable $9,269  $384,285  $1,021  $—  $394,575  $7,315  $(11,452) $390,438 
Accrued liabilities  15,086   8,118   11   —   23,215   20,921   (2,351)  41,785 
Other liabilities  (8,130)  8,130   —   —   —   —   —   — 
Short-term debt  —   —   —   —   —   29,000   —   29,000 
Current liabilities of discontinued operations  —   —   —   —   —   935   —   935 
                         
Total current liabilities  16,225   400,533   1,032   —   417,790   58,171   (13,803)  462,158 
                                 
Long-term debt  —   —   —   —   —   341,914   —   341,914 
Non-current liabilities  41,693   5,033   —   —   46,726   17,604   —   64,330 
Deferred income taxes  24,894   44,597   —   —   69,491   —   —   69,491 
Distributions in excess of inv in HEP  —   326,889   —   —   326,889   —   (326,889)  — 
Equity — Holly Corporation  542,399   1,911,613   77,645   (1,989,258)  542,399   30,142   (31,001)  541,540 
Equity — Noncontrolling interest  —   —   —   26,684   26,684   10,218   357,890   394,792 
                         
Total liabilities and equity $625,211  $2,688,665  $78,677  $(1,962,574) $1,429,979  $458,049  $(13,803) $1,874,225 
                         

-108-

Condensed Consolidating Statement of Income
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
Year Ended December 31, 2009 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
Sales and other revenues $3,346  $4,785,781  $58  $—  $4,789,185  $146,561  $(101,478) $4,834,268 
                                 
Operating costs and expenses:                                
Cost of products sold  —   4,336,973   900   —   4,337,873   —   (99,865)  4,238,008 
Operating expenses  —   313,361   —   —   313,361   44,003   (509)  356,855 
General and administrative expenses  51,648   1,318   (209)  —   52,757   7,586   —   60,343 
Depreciation and amortization  3,928   68,956   1,268   —   74,152   24,599   —   98,751 
                         
                                 
Total operating costs and expenses  55,576   4,720,608   1,959   —   4,778,143   76,188   (100,374)  4,753,957 
                         
                                 
Income (loss) from operations  (52,230)  65,173   (1,901)  —   11,042   70,373   (1,104)  80,311 
                                 
Other income (expense):                                
Equity in earnings of subsidiaries  96,266   31,643   33,052   (127,909)  33,052   —   (33,052)  — 
Interest income (expense)  (13,713)  1,096   44   —   (12,573)  (21,490)  (1,238)  (35,301)
Other income (expense)  (1,480)  1,480   —   —   —   1,986   (67)  1,919 
Acquisition costs  —   (3,126)  —   —   (3,126)  (1,356)  1,356   (3,126)
                         
                                 
   81,073   31,093   33,096   (127,909)  17,353   (20,860)  (33,001)  (36,508)
                         
                                 
Income (loss) from continuing operations before income taxes  28,843   96,266   31,195   (127,909)  28,395   49,513   (34,105)  43,803 
                                 
Income tax provision  10,295   —   —   —   10,295   20   (2,855)  7,460 
                         
                                 
Income from continuing operations  18,548   96,266   31,195   (127,909)  18,100   49,493   (31,250)  36,343 
                                 
Income from discontinued operations  —   —   —   —   —   19,780   (2,854)  16,926 
                         
                                 
Net Income  18,548   96,266   31,195   (127,909)  18,100   69,273   (34,104)  53,269 
                                 
Less net income attributable to noncontrolling interest  —   —   —   (448)  (448)  —   34,184   33,736 
                         
                                 
Net income attributable to Holly Corporation stockholders $18,548  $96,266  $31,195  $(127,461) $18,548  $69,273  $(68,288) $19,533 
                         
Condensed Consolidating Statement of Income
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
Year Ended December 31, 2008 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
Sales and other revenues $1,831  $5,838,244  $15  $—  $5,840,090  $94,439  $(74,172) $5,860,357 
                                 
Operating costs and expenses:                                
Cost of products sold  23   5,354,561   —   —   5,354,584   —   (73,885)  5,280,699 
Operating expenses  17   231,995   627   —   232,639   33,353   (287)  265,705 
General and administrative expenses  46,230   3,434   —   —   49,664   5,614   —   55,278 
Depreciation and amortization  3,627   40,299   679   —   44,605   18,390   —   62,995 
                         
                                 
Total operating costs and expenses  49,897   5,630,289   1,306   —   5,681,492   57,357   (74,172)  5,664,677 
                         
                                 
Income (loss) from operations  (48,066)  207,955   (1,291)  —   158,598   37,082   —   195,680 
                                 
Other income (expense):                                
Equity in earnings of subsidiaries  257,587   15,700   16,633   (273,287)  16,633   —   (13,643)  2,990 
Interest income (expense)  (23,875)  31,698   507   —   8,330   (21,488)  —   (13,158)
Net gain (loss)  —   2,234   —   —   2,234   —   —   2,234 
                         
                                 
   233,712   49,632   17,140   (273,287)  27,197   (21,488)  (13,643)  (7,934)
                         
                                 
Income (loss) from continuing operations before income taxes  185,646   257,587   15,849   (273,287)  185,795   15,594   (13,643)  187,746 
                                 
Income tax provision  64,537   —   —   —   64,537   238   (747)  64,028 
                         
                                 
Income from continuing operations  121,109   257,587   15,849   (273,287)  121,258   15,356   (12,896)  123,718 
                                 
Income from discontinued operations  —   —   —   —   —   3,665   (747)  2,918 
                         
                                 
Net Income  121,109   257,587   15,849   (273,287)  121,258   19,021   (13,643)  126,636 
                                 
Less net income attributable to noncontrolling interest  —   —   —   (149)  (149)  —   (6,227)  (6,078)
                         
                                 
Net income attributable to Holly Corporation stockholders $121,109  $257,587  $15,849  $(273,138) $121,407  $19,021  $(19,870) $120,558 
                         

-109-

Condensed Consolidating Statement of Income
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
Year Ended December 31, 2007 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
Sales and other revenues $13  $4,791,729  $—  $—  $4,791,742  $—  $—  $4,791,742 
                                 
Operating costs and expenses:                                
Cost of products sold  —   3,999,931   3,557   —   4,003,488   —   —   4,003,488 
Operating expenses  12   209,192   77   —   209,281   —   —   209,281 
General and administrative expenses  66,305   2,880   —   —   69,185   —   —   69,185 
Depreciation and amortization  2,245   41,211   —   —   43,456   —   —   43,456 
                         
                                 
Total operating costs and expenses  68,562   4,253,214   3,634   —   4,325,410   —   —   4,325,410 
                         
                                 
Income (loss) from operations  (68,549)  538,515   (3,634)  —   466,332   —   —   466,332 
                                 
Other income (expense):                                
Equity in earnings of subsidiaries  653,060   15,233   19,109   (668,293)  19,109   —   —   19,109 
Interest income (expense)  (85,067)  99,312   (242)  —   14,003   —   —   14,003 
                         
                                 
   567,993   114,545   18,867   (668,293)  33,112   —   —   33,112 
                         
                                 
Income (loss) from continuing operations before income taxes  499,444   653,060   15,233   (668,293)  499,444   —   —   499,444 
                                 
Income tax provision  165,316   —   —   —   165,316   —   —   165,316 
                         
                                 
Net income attributable to Holly Corporation stockholders $334,128  $653,060  $15,233  $(668,293) $334,128  $—  $—  $334,128 
                         

-110-

Condensed Consolidating Statement of Cash Flows
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
Year Ended December 31, 2009 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
Cash flows from operating activities $(277,912) $448,020  $308  $—  $170,416  $68,195  $(27,066) $211,545 
                                 
Cash flows from investing activities                                
Additions to properties, plants and equipment — Holly  (2,904)  (215,343)  (51,305)  —   (269,552)  (25,665)  —   (295,217)
Additions to properties, plants and equipment — HEP  —   —   —   —   —   (128,079)  95,080   (32,999)
Purchases of marketable securities  (175,892)  —   —   —   (175,892)  —   —   (175,892)
Sales and maturities of marketable securities  230,281   —   —   —   230,281   —   —   230,281 
Acquisition of Tulsa Refinery — Holly Corporation  74,000   (341,141)  —   —   (267,141)  —   —   (267,141)
Investment in SLC Pipeline  —   —   —   —   —   (25,500)  —   (25,500)
Proceeds from the sale of assets  —   83,280   —   —   83,280   —   (83,280)  — 
Proceeds from sale of RGPC  —   —   —   —   —   31,865   —   31,865 
                         
                                 
Net cash provided by (used for) investing activities  125,485   (473,204)  (51,305)  —   (399,024)  (147,379)  11,800   (534,603)
                         
                                 
Cash flows from financing activities                                
Net borrowings under credit agreement  —   —   —   —   —   6,000   —   6,000 
Issuance of common units net of underwriter’s discount  —   —   —   —   —   133,035   —   133,035 
Dividends  (30,123)  —   —   —   (30,123)  —   —   (30,123)
Distributions to noncontrolling interest  —   —   —   —   —   (62,688)  29,488   (33,200)
Purchase of treasury stock  (1,214)  —   —   —   (1,214)  —   —   (1,214)
Contribution from joint venture partner  —   (39,450)  54,600   —   15,150   —   —   15,150 
Excess tax benefit from equity based compensation  (1,209)  —   —   —   (1,209)  —   —   (1,209)
Deferred financing costs  (8,842)  —   —   —   (8,842)  —   —   (8,842)
Proceeds from issuance of notes, net of underwriter discount — HOC  287,925   —   —   —   287,925   —   —   287,925 
Proceeds from Plains financing transaction  —   40,000   —   —   40,000   —   —   40,000 
Other financing activities, net  134   13,339   —   —   13,473   76   (14,222)  (673)
                         
                                 
Net cash provided by financing activities  246,671   13,889   54,600   —   315,160   76,423   15,266   406,849 
                         
                                 
Cash and cash equivalents                                
Increase (decrease) for the period  94,244   (11,295)  3,603   —   86,552   (2,761)  —   83,791 
Beginning of period  33,316   (1,182)  3,402   —   35,536   5,269   —   40,805(1)
                         
                                 
End of period $127,560  $(12,477) $7,005  $—  $122,088  $2,508  $—  $124,596 
                         
                                 
(1)Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008.

-111-

Condensed Consolidating Statement of Cash Flows
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
Year Ended December 31, 2008 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
Cash flows from operating activities $(63,480) $192,299  $364  $—  $129,183  $46,091  $(19,784) $155,490 
                                 
Cash flows from investing activities                                
Additions to properties, plants and equipment — Holly  (2,515)  (295,937)  (85,290)  —   (383,742)  —   —   (383,742)
Additions to properties, plants and equipment — HEP  —   —   —   —   —   (34,317)  —   (34,317)
Purchases of marketable securities  (769,142)  —   —   —   (769,142)  —   —   (769,142)
Sales and maturities of marketable securities  945,461   —   —   —   945,461   —   —   945,461 
Proceeds from sale of crude pipeline and tankage assets  —   171,000   —   —   171,000   —   —   171,000 
Proceeds from sale of HPI  —   5,958   —   —   5,958   —   —   5,958 
Increase in cash due to consolidation of HEP  —   —   —   —   —   —   7,295   7,295 
Investment in HEP  —   (290)  —   —   (290)  —   —   (290)
                         
                                 
Net cash provided by (used for) investing activities  173,804   (119,269)  (85,290)  —   (30,755)  (34,317)  7,295   (57,777)
                         
                                 
Cash flows from financing activities                                
Net borrowings under credit agreement  —   —   —   —   —   29,000   —   29,000 
Issuance of common stock upon exercise of options  1,005   —   —   —   1,005   —   —   1,005 
Dividends  (29,054)  —   —   —   (29,054)  —   (10)  (29,064)
Distributions to noncontrolling interest  —   —   —   —   —   (41,603)  19,505   (22,098)
Purchase of treasury stock  (151,106)  —   —   —   (151,106)  —   —   (151,106)
Contribution from joint venture partner  (1,500)  (55,500)  74,000   —   17,000   —   —   17,000 
Excess tax benefit from equity based compensation  5,694   —   —   —   5,694   —   —   5,694 
Deferred financing costs      (800)  —   —   (800)  (113)  —   (913)
Purchase of units for restricted grants  —   —   —   —   —   (795)  —   (795)
                         
                                 
Net cash provided by (used for) financing activities  (174,961)  (56,300)  74,000   —   (157,261)  (13,511)  19,495   (151,277)
                         
                                 
Cash and cash equivalents                                
Increase (decrease) for the period  (64,637)  16,730   (10,926)  —   (58,833)  (1,737)  7,006   (53,564)
Beginning of period  97,953   (17,912)  14,328   —   94,369   7,006   (7,006)  94,369 
                         
                                 
End of period $33,316  $(1,182) $3,402  $—  $35,536  $5,269  $—  $40,805(1)
                         
                                 
(1)Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008.

-112-

Condensed Consolidating Statement of Cash Flows
                                 
          Non-      Holly Corp.  Non-Guarantor       
      Guarantor  Guarantor      Before  Non-Restricted       
      Restricted  Restricted      Consolidation  Subsidiaries       
Year Ended December 31, 2007 Parent  Subsidiaries  Subsidiaries  Eliminations  of HEP(1)  (HEP Segment)  Eliminations  Consolidated 
  (In thousands) 
Cash flows from operating activities $283,276  $144,406  $(4,945) $—  $422,737  $—  $—  $422,737 
                                 
Cash flows from investing activities                                
Additions to properties, plants and equipment — Holly  (9,810)  (170,762)  19,314   —   (161,258)  —   —   (161,258)
Purchases of marketable securities  (641,144)  —   —   —   (641,144)  —   —   (641,144)
Sales and maturities of marketable securities  509,345   —   —   —   509,345   —   —   509,345 
                         
                                 
Net cash provided by (used for) investing activities  (141,609)  (170,762)  19,314   —   (293,057)  —   —   (293,057)
                         
                                 
Cash flows from financing activities                                
Dividends  (23,208)  —   —   —   (23,208)  —   —   (23,208)
Purchase of treasury stock  (207,196)  —   —   —   (207,196)  —   —   (207,196)
Contribution from joint venture partner  —   8,333   —   —   8,333   —   —   8,333 
Excess tax benefit from equity based compensation  30,355   —   —   —   30,355   —   —   30,355 
Issuance of common stock upon exercise of options  2,288   —   —   —   2,288   —   —   2,288 
                         
                                 
Net cash provided by (used for) financing activities  (197,761)  8,333   —   —   (189,428)  —   —   (189,428)
                         
                                 
Cash and cash equivalents                                
Increase (decrease) for the period  (56,094)  (18,023)  14,369   —   (59,748)  —   —   (59,748)
Beginning of period  154,047   111   (41)  —   154,117   —   —   154,117 
                         
                                 
End of period $97,953  $(17,912) $14,328  $—  $94,369  $—  $—  $94,369 
                         
(1)Includes Holly Corporation’s investment in HEP based on the equity method of accounting.
NOTE 19:21: 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$114.6 million (2%) of our revenues in 2009, $325.4 million (6%) of our revenues in 2008 $200.0and $200 million (5%) of our revenues in 20072007. In 2009, 2008 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 20:22: Quarterly Information (Unaudited)
                                        
 First Second Third Fourth   First Second Third Fourth   
 Quarter Quarter Quarter Quarter Year Quarter Quarter Quarter Quarter Year 
 (In thousands except share data) (In thousands, except per share data) 
Year Ended December 31, 2008
 
 
Year Ended December 31, 2009
 
Sales and other revenues $1,479,984 $1,743,822 $1,719,920 $923,942 $5,867,668  $648,031 $1,035,778 $1,488,490 $1,661,969 $4,834,268 
Operating costs and expenses $1,470,391 $1,723,596 $1,636,944 $836,405 $5,667,336  $610,240 $998,327 $1,432,908 $1,712,482 $4,753,957 
Income from operations $9,593 $20,226 $82,976 $87,537 $200,332  $37,791 $37,451 $55,582 $(50,513) $80,311 
Income from continuing operations before income taxes $13,344 $17,308 $75,649 $79,083 $185,384  $33,922 $29,258 $43,676 $(63,053) $43,803 
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 
Net income attributable to Holly Corporation stockholders $21,964 $14,621 $23,503 $(40,555) $19,533 
Net income per share attributable to Holly Corporation stockholders — basic $0.44 $0.29 $0.47 $(0.79) $0.39 
Net income per share attributable to. Holly Corporation stockholders — diluted $0.44 $0.29 $0.47 $(0.79) $0.39 
Dividends per common share $0.15 $0.15 $0.15 $0.15 $0.60  $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  50,042 50,170 50,244 51,200 50,418 
Diluted 51,515 50,515 50,032 49,997 50,549  50,171 50,226 50,327 51,380 50,603 

-91-

-113-

                                        
 First Second Third Fourth   First Second Third Fourth   
 Quarter Quarter Quarter Quarter Year Quarter Quarter Quarter Quarter Year 
 (In thousands except share data) (In thousands, except per share data) 
Year Ended December 31, 2007
 
 
Year Ended December 31, 2008
 
Sales and other revenues $925,867 $1,216,997 $1,208,671 $1,440,207 $4,791,742  $1,479,194 $1,741,654 $1,718,276 $921,233 $5,860,357 
Operating costs and expenses $829,293 $980,447 $1,141,039 $1,374,631 $4,325,410  $1,470,050 $1,722,733 $1,636,305 $835,589 $5,664,677 
Income from operations $96,574 $236,550 $67,632 $65,576 $466,332  $9,144 $18,921 $81,971 $85,644 $195,680 
Income from continuing operations before income taxes $102,228 $244,763 $77,267 $75,186 $499,444  $13,692 $16,482 $76,484 $81,088 $187,746 
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 
Net income attributable to Holly Corporation stockholders $8,649 $11,452 $49,899 $50,558 $120,558 
Net income per share attributable to Holly Corporation stockholders — basic $0.17 $0.23 $1.00 $1.02 $2.40 
Net income per share attributable to Holly Corporation stockholders — diluted $0.17 $0.23 $1.00 $1.01 $2.38 
Dividends per common share $0.10 $0.12 $0.12 $0.12 $0.46  $0.15 $0.15 $0.15 $0.15 $0.60 
Average number of shares of common stock outstanding  
Basic 55,189 54,959 54,819 54,451 54,852  51,165 50,158 49,717 49,794 50,202 
Diluted 56,318 55,953 55,853 55,098 55,850  51,515 50,515 50,032 49,997 50,549 

-92-

-114-

Item 9.
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.
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 ourOur disclosure controls and procedures are effective in ensuringdesigned to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2009.
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.
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 20082009 that would need to be reported on Form 8-K that have not previously been reported.
PART III
Item 10.
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, 20095, 2010 and is incorporated herein by reference.
New York Stock Exchange Certification
In 2008,2009, 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.
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, 20095, 2010 and is incorporated herein by reference.

-93-

-115-

Item 12.
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, 20095, 2010 and is incorporated herein by reference.
Item 13.
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, 20095, 2010 and is incorporated herein by reference.
Item 14.
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, 20095, 2010 and is incorporated herein by reference.

-94-

-116-

PART IV
Item 15.
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  6475 
     
Consolidated Balance Sheets at December 31, 20082009 and 20072008  6576 
     
Consolidated Statements of Income for the years ended December 31, 2009, 2008 2007 and 20062007  6677 
     
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 2007 and 20062007  6778 
     
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009, 2008 2007 and 20062007  6879 
     
Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 2007 and 20062007  6980 
     
Notes to Consolidated Financial Statements  7081 
 (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 98120 to 101.125.

-95-

-117-

SIGNATURES
Pursuant to the requirements of Section 13 or15(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, 200926, 2010
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, 200926, 2010
     
/s/ Bruce R. Shaw
 
Bruce R. Shaw
 Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)		 February 27, 200926, 2010
     
/s/ Scott C. Surplus
 
Scott C. Surplus
 Vice President and Controller
(Principal (Principal Accounting Officer)		 February 27, 200926, 2010
     
/s/ Denise C. McWatters
 
Denise C. McWatters
 Vice President, General
Counsel and Secretary		 February 27, 200926, 2010
     
/s/ Buford P. Berry
 
Buford P. Berry
 Director  February 27, 200926, 2010
     
/s/ Leldon E. Echols
 
Leldon E. Echols
 Director  February 27, 200926, 2010
     
/s/ Marcus R. Hickerson
 
Marcus R. Hickerson
 Director  February 27, 200926, 2010
     
/s/ Robert G. McKenzie
 
Robert G. McKenzie
 Director  February 27, 200926, 2010
    

-96-

SignatureCapacityDate
 
/s/ Thomas K. Matthews, II
 
Thomas K. Matthews, II
 Director  February 27, 200926, 2010
     
/s/ Jack P. Reid
 
Jack P. Reid
 Director  February 27, 200926, 2010
     
/s/ Paul T. Stoffel
     Paul T. Stoffel
 Director February 27, 200926, 2010
Paul T. Stoffel

-97--118-

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 PurchaseAsset Sale and SalePurchase Agreement, dated February 25, 2008October 19, 2009 by and between Holly Corporation, Navajo Pipeline Co., L.P., NavajoRefining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa 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.’sRegistrant’s Current Report on Form 8-K filed February 27, 2008,October 21, 2009, File No. 1-32225)1-03876).
   
2.2Amendment No. 1 to Asset Sale and Purchase Agreement, dated December 1, 2009, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant’s Current Report on Form 8-K filed December 7, 2009, File No. 1-03876).
2.3Asset Sale and Purchase Agreement dated as of April 15, 2009 by and between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 2.1 of Registrant’s Current Report on Form 8-K filed April 16, 2009, File No. 1-03876).
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+3.2 Certificate of Amendment to the Restated Certificate of Incorporation of Holly Corporation, adopted May 26, 2004.2004 (incorporated by reference to Exhibit 3.2 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876).
   
3.3+3.3 Certificate of Amendment to the Restated Certificate of Incorporation of Holly Corporation, adopted May 29, 2007.2007 (incorporated by reference to Exhibit 3.3 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876).
   
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).
  
4.1Registration Rights and Transfer Restrictions Agreement, dated October 19, 2009 by and between Holly Corporation and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K filed October 20, 2009, File No. 1-03876).
 
4.2Indenture, dated as of June 10, 2009, among Holly Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee, relating to Holly Corporation’s 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued thereunder) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated June 11, 2009, File No. 1-03876).
4.3 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).

-119-

   
4.2Exhibit
NumberDescription
4.4 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).
   
4.34.5 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).
   
4.44.6 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).
   
4.54.7 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).
   
4.8+ Third Supplemental Indenture, dated as of June 11, 2009, among Lovington-Artesia, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors identified therein, and U.S. Bank National Association.
4.9+ Fourth Supplemental Indenture, dated as of June 29, 2009, among HEP SLC, LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association.
4.10+ Fifth Supplemental Indenture, dated as of July 13, 2009, among HEP Tulsa LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association.
4.11+ Sixth Supplemental Indenture, dated as of December 15, 2009, among Roadrunner Pipeline, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association.
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).
10.2Amended and Restated Intermediate Pipelines Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Holly Energy Partners, L.P.’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).
10.3Tulsa Equipment and Throughput Agreement, dated as of August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Holly Energy Partners L.P.’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225).

-98-

-120-

   
Exhibit  
Number Description
   
10.210.4 Tulsa Purchase Option agreement, dated as of August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Holly Energy Partners L.P.’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225).
10.5Amended and Restated Crude Pipelines and Tankage Agreement, dated February 29, 2008, between Holly Corporation, Navajo Pipeline Co., L.P.,as of December 1, 2009, by and among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company — Woods Cross, Holly Refining & Marketing Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating,Partners-Operating, L.P., HEP Pipeline, L.L.C., and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.110.8 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 6, 2008,dated December 7, 2009, File No. 1-32225).
   
10.3*10.6Amended and Restated Refined Product Pipelines and Terminals Agreement, dated as of December 1, 2009, by and among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company — Woods Cross, Holly Energy Partners-Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225).
10.7Third Amended and Restated Omnibus Agreement, dated as of December 1, 2009, by and among Holly Corporation, Holly Energy Partners, L.P., and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225).
10.8Pipeline Throughput Agreement, dated as of December 1, 2009, by and between Navajo Refining Company, L.L.C. and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.4 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225).
10.9Pipelines, Tankage, and Loading Rack Throughput Agreement, dated December 1, 2009 by and between HEP Tulsa LLC and Holly Refining & Marketing-Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-03876).
10.10Indemnification Proceeds and Payments Allocation Agreement, dated December 1, 2009 by and between HEP Tulsa LLC and Holly Refining & Marketing-Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-03876).
10.11Lease and Access Agreement, dated December 1, 2009 by and between HEP Tulsa LLC and Holly Refining & Marketing-Tulsa LLC (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-03876).
10.12*  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*+10.13*  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, 2007.2007 (incorporated by reference to Exhibit 10.4 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876).

-121-

Exhibit
NumberDescription
   
10.5*+10.14*  Amendment No. 1 to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated on May 24, 2007.2007 (incorporated by reference to Exhibit 10.5 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876).
   
10.6*10.15*  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*10.16*  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*10.17*  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*+10.18First 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).

-99-

Exhibit
NumberDescription
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*10.19*  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*10.20*  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+10.21 First Amendment to Performance Share Unit Agreement.Agreement (incorporated by reference to Exhibit 10.16 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876).
   
10.1710.22 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).
   
10.1810.23 HolyHolly 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).
   
10.1910.24 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).
   
10.2010.25* Form of Executive Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009).
10.26* Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009).
10.27* Form of Director Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009).

-122-

Exhibit
NumberDescription
10.28* Form of Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.5 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009).
10.29 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).
   
10.2110.30Reaffirmation 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 10.31 below) (incorporated by reference to Exhibit 10.22 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876).
10.31 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+10.32 ReaffirmationSecond Amended and AssumptionRestated Credit Agreement dated March 14, 2008,April 7, 2009 by and among Holly Corporation the subsidiaries identified therein, the additional grantors identified therein and Bank of America, N.A. (adding additional grantors under, as administrative agent, swing line lender, and L/C issuer, UBS Loan Finance LLC and U.S. Bank National Association, as co-documentation agents, Union Bank of California, N.A. and Compass Bank, as syndication agents, and certain other lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the Guaranty and Collateral Agreement included as Exhibit 10.22 above)quarter ended March 31, 2009, File No. 1-03876).
   
10.2310.33+ Confirmation of Commitments [reflects increases in commitments on November 3, 2009 and December 4, 2009 under the Second Amended and Restated Credit Agreement filed as Exhibit 10.35 to this Annual Report on Form 10-K].
10.34First Amendment to Guarantee and Collateral Agreement and Reaffirmation and Assumption Agreement, dated April 7, 2009, by and among Holly Corporation and certain of its subsidiaries, in favor of Bank of America, N.A., as administrative agent, for certain other lenders from time to time party to the Second Amended and Restated Credit Agreement dated April 7, 2009 (incorporated by reference to Exhibit 10.5 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-03876).
10.35 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).
   
10.2410.36 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).

-100-

-123-

   
Exhibit  
Number Description
   
10.2510.37 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).
   
10.2610.38 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).
   
10.2710.39 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)
   
10.2810.40 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)
   
10.2910.41 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*10.42*  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+21.1+  Subsidiaries of Registrant.
   
23.1+23.1+  Consent of Independent Registered Public Accounting Firm.
   
31.1+31.1+  Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
   
31.2+31.2+  Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
   
32.1+32.1+  Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
   
32.2+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.

-101-

-124-