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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
Commission File Number 1-32225
HOLLY ENERGY PARTNERS, L.P.
Formed under the laws of the State of Delaware
I.R.S. Employer Identification No. 20-0833098
100 Crescent Court, Suite 1600
Dallas, Texas 75201-6915
Telephone Number: (214) 871-3555
Securities registered pursuant to Section 12(b) of the Act:
Common Limited Partner Units
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in part III of this Form 10-K or any amendments to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer oAccelerated filer þ 
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $352 million on June 30, 2008, based on the last sales price as quoted on the New York Stock Exchange.
The number of the registrant’s outstanding common limited partners units at February 6, 2009 was 8,390,000.
DOCUMENTS INCORPORATED BY REFERENCE: None
 
 

 


 

TABLE OF CONTENTS
             
Item       Page
 
           
 
  PART I        
 
           
Forward-Looking Statements     3  
 
           
  Business     5  
  Risk factors     13  
  Unresolved staff comments     30  
  Properties     30  
  Legal proceedings     37  
  Submission of matters to a vote of security holders     37  
 
           
 
  PART II        
 
           
  Market for the Registrant’s common units, related unitholder matters and issuer purchases of common units     38  
  Selected financial data     40  
  Management’s discussion and analysis of financial condition and results of operations     43  
  Quantitative and qualitative disclosures about market risk     60  
  Financial statements and supplementary data     61  
  Changes in and disagreements with accountants on accounting and financial disclosure     90  
  Controls and procedures     90  
  Other information     90  
 
           
 
  PART III        
 
           
  Directors, executive officers and corporate governance     91  
  Executive compensation     96  
  Security ownership of certain beneficial owners and management and related unitholder matters     121  
  Certain relationships, related transactions and director independence     122  
  Principal accountant fees and services     126  
 
           
 
  PART IV        
 
           
  Exhibits and financial statement schedules     128  
 
           
Signatures     134  
 EX-10.12
 EX-10.13
 EX-10.14
 EX-10.15
 EX-10.26
 EX-10.27
 EX-10.37
 EX-12.1
 EX-21.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

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PART I
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business”, “Risk Factors” and “Properties” in Items 1, 1A and 2 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 beliefs 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 differ materially 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 actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled in our terminals;
 
    The economic viability of Holly Corporation, Alon USA, Inc. and our other customers;
 
    The demand for refined petroleum products in markets we serve;
 
    Our ability to successfully purchase and integrate additional operations in the future;
 
    Our ability to complete previously announced pending or contemplated acquisitions;
 
    The availability and cost of additional debt and equity financing;
 
    The possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;
 
    The effects of current and future government regulations and policies;
 
    Our operational efficiency in carrying out routine operations and capital construction projects;
 
    The possibility of terrorist attacks and the consequences of any such attacks;
 
    General economic conditions; and
 
    Other financial, operations 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 the 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. All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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INDEX TO DEFINED TERMS AND NAMES
The following terms and names that appear in this form 10-K are defined on the following pages:
         
Alon
    5  
Alon PTA
    5  
ARB
    58  
Big Spring Refinery
    5  
BP
    15  
bpd
    6  
Credit Agreement
    10  
Crude Pipelines and Tankage Assets
    5  
Distributable cash flow
    41  
DOT
    10  
EBITDA
    41  
EITF
    58  
Expansion capital expenditures
    8  
FASB
    58  
FERC
    6  
Fixed Rate Swap
    59  
FSP
    58  
GAAP
    41  
HEP
    5  
HLS
    5  
Holly
    5  
Holly CPTA
    5  
Holly IPA
    5  
Holly PTA
    5  
Intermediate Pipelines
    5  
LPG
    6  
Maintenance capital expenditures
    42  
mbbls
    31  
mbpd
    50  
Mid-America
    31  
MLP
    58  
NPL
    5  
NuStar
    35  
Omnibus Agreement
    6  
Plains
    9  
PPI
    6  
Rio Grande
    6  
SEC
    5  
SFAS
    58  
Sinclair
    36  
SLC Pipeline
    9  
ULSD
    49  
UNEV Pipeline
    9  
Valero
    35  
Variable Rate Swap
    59  
Terms used in the financial statements and footnotes are as defined therein.

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Item 1. Business
OVERVIEW
Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership formed by Holly Corporation and is the successor to Navajo Pipeline Co., L.P. (Predecessor) (“NPL”). We operate a system of refined product and crude oil pipelines, storage tanks and distribution terminals primarily in west Texas, New Mexico, Utah and Arizona. We maintain our principal corporate offices at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915. Our telephone number is 214-871-3555 and our internet website address is www.hollyenergy.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission (“SEC”) website is available on our website on the Investors page. Additionally available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation 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. In this document, the words “we”, “our”, “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person. “Holly” refers to Holly Corporation and its subsidiaries, other than HEP and its subsidiaries and other than Holly Logistic Services, L.L.C. (“HLS”), a subsidiary of Holly Corporation that is the general partner of the general partner of HEP and manages HEP.
We generate revenues by charging tariffs for transporting refined product and crude oil through our pipelines and by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at our terminals. We do not take ownership of products that we transport or terminal; therefore, we are not directly exposed to changes in commodity prices. We serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline, terminal and tankage agreements with Holly. One of these agreements relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering in 2004 and expires in 2019 (“Holly PTA”). Our second agreement with Holly relates to the intermediate pipelines acquired from Holly in July 2005 (“Intermediate Pipelines”) that serve Holly’s Lovington and Artesia, New Mexico refinery facilities (collectively, the “Navajo Refinery”) and expires in 2020 (“Holly IPA”). Our third agreement, relates to the crude pipelines and tankage assets acquired from Holly in February 2008 (the “Crude Pipelines and Tankage Assets”) and expires in 2023 (“Holly CPTA”). We also serve the Alon USA, Inc. (“Alon”) Big Spring, Texas refinery (“Big Spring Refinery”) under the Alon pipelines and terminals agreement expiring in 2020 (“Alon PTA”). The substantial majority of our business is devoted to providing transportation and terminalling services to Holly. We operate our business as one business segment.
Our 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 Holly’s Navajo Refinery in New Mexico to its 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 Holly’s Lovington, New Mexico refinery facilities to Holly’s Artesia, New Mexico refinery facilities;
 
    approximately 860 miles of crude oil trunk, gathering and connection pipelines located in west Texas and New Mexico that deliver crude oil to Holly’s Navajo Refinery;

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    approximately 10 miles of crude oil and refined product pipelines that support Holly’s Woods Cross Refinery near Salt Lake City, Utah; and
 
    a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), a joint venture that owns a 249-mile refined product pipeline that transports liquid petroleum gases (“LPG”) from west Texas to the Texas/Mexico border near El Paso for further transport into northern Mexico.
     Refined Product Terminals and Refinery Tankage:
    four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,000,000 barrels, that are integrated with our refined product pipeline system that serves Holly’s 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 our refined product pipelines that serve Alon’s Big Spring Refinery;
 
    two refined product truck loading racks, one located within Holly’s Navajo Refinery that is permitted to load over 40,000 barrels per day (“bpd”) of light refined products, and one located within Holly’s Woods Cross Refinery, 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 Holly’s Navajo and Woods Cross Refineries having an aggregate storage capacity of approximately 600,000 barrels.
Holly Crude Pipelines and Tankage Transaction
On February 29, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly for $180.0 million that consist of crude oil trunk lines that deliver crude oil to Holly’s 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, a leased jet fuel terminal in Roswell, New Mexico and crude oil and refined product pipelines that support Holly’s Woods Cross Refinery. The consideration paid consisted of $171.0 million in cash and 217,497 of our common units having a fair value of $9.0 million. We financed the $171.0 million cash portion of the consideration through borrowings under our senior secured revolving credit agreement expiring August 2011.
In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with Holly. Under the Holly CPTA, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities that at the agreed rates will result in minimum annual payments to us of $26.8 million. These minimum annual payments or revenue will be 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 will generally be increased annually by the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC index is the change in the PPI plus a FERC adjustment factor which is reviewed periodically. Additionally, Holly amended our omnibus agreement (the “Omnibus Agreement”) to provide $7.5 million of indemnification for a period of up to fifteen years for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our acquisition.

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Agreements with Holly and Alon
In addition to the Holly CPTA, the Holly PTA relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering in 2004 and expires in 2019, and the Holly IPA that relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020. Under these agreements, Holly has agreed to transport and store volumes of refined product on our pipelines and terminal facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under the Holly PTA and Holly IPA, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI, but generally will not decrease as a result of a decrease in the PPI.
We also have a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that results in a minimum level of annual revenue. Under the Alon PTA, the agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.
As of December 31, 2008, contractual minimums under our long-term service agreements are as follows:
                         
    Minimum Annualized              
    Commitment              
Agreement   (In millions)     Year of Maturity     Contract Type
 
                       
Holly PTA
  $ 41.2       2019     Minimum revenue commitment
Holly IPA
    13.3       2020     Minimum revenue commitment
Holly CPTA
    26.8       2023     Minimum revenue commitment
Alon PTA
    22.0       2020     Minimum volume commitment
Alon capacity lease
    6.8     Various     Capacity lease
 
                     
 
                       
Total
  $ 110.1                  
 
                     
We depend on our agreements with Holly and Alon for the majority of our revenues. A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.
Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right after we have made efforts to mitigate their effects to negotiate a monthly surcharge on Holly for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly’s pro rata portion of the cost of complying with these laws or regulations including a reasonable rate of return. In such instances, we will negotiate in good faith with Holly to agree on the level of the monthly surcharge or increased tariff rate.
Under certain circumstances, certain of Holly’s obligations under these agreements may be temporarily suspended or terminated.
Omnibus Agreement
Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Initially, this fee was $2.0 million for each of the three years following the closing of our initial public offering. Effective March 1, 2008, the annual fee was increased to $2.3 million to cover additional general and administrative services attributable to the operations of our Crude Pipelines and Tankage Assets. This fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury,

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information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees.
Under the Omnibus Agreement, Holly has also agreed to indemnify us up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to us and occurring or existing prior to the date of such transfers. The Omnibus Agreement provides environmental indemnification of up to $15.0 million through 2014 for the assets transferred to us at the time of our initial public offering in 2004 and up to $2.5 million through 2015 for the Intermediate Pipelines acquired in July 2005. In February 2008, Holly amended the Omnibus Agreement to provide an additional $7.5 million of indemnification through 2023 for environmental noncompliance and remediation liabilities specific to the Crude Pipelines and Tankage Assets.
Alon
In connection with our purchase of certain refined products pipelines, tankage and terminals from Alon in 2005, we entered into a 15-year pipelines and terminals agreement with Alon to transport and terminal light refined products for Alon’s refinery in Big Spring, Texas. Under the Alon PTA, Alon agreed to transport on our pipelines and throughput in our terminals a volume of refined products that would result in minimum revenue levels each year that will change annually based on changes in the PPI, but will not decrease below the initial $20.2 million annual amount. Following the March 1, 2008 PPI adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2009 is $22.0 million.
Alon’s minimum volume commitment was calculated based on 90% of Alon’s then recent usage of these pipelines and terminals taking into account an expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted each year for changes in the PPI, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the Alon PTA may be reduced or suspended under certain circumstances. Additionally, we entered into an environmental agreement expiring in 2015 with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon, whereby Alon will indemnify us subject to a $100,000 deductible and a $20.0 million maximum liability cap.
CAPITAL REQUIREMENTS
Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety and to address environmental regulations. Expansion capital expenditures represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.
Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated to a particular capital project may be expended over a period in excess of a year, depending on the time required to complete

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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. The 2009 capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of the South System and the joint venture with Plains All American Pipeline, L.P. (“Plains”) discussed below.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our pipeline system between Artesia, New Mexico and El Paso, Texas (the “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 our 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. We expect to complete the majority of this project in early 2009.
In November 2007, we 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 us. We expect to purchase our 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 Holly’s 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 our investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to Holly upon the closing of our investment in the SLC Pipeline.
On January 31, 2008, we entered into an option agreement with Holly, granting us an option to purchase all of Holly’s equity interests in a joint venture pipeline currently under construction. The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the “UNEV Pipeline”). Holly owns 75% of the equity interests in the UNEV Pipeline. Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. 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. Holly’s share of this cost is $225.0 million. On July 17, 2008, Holly announced the purchase of Musket Corporation’s Cedar City, Utah terminal and rail facilities that will serve as part of the UNEV Pipeline’s Cedar City Terminal. Holly’s UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, Holly is currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.
Holly is currently working on a project to deliver additional crude oils to its Navajo Refinery, including a 70-mile pipeline from Centurion Pipeline L.P.’s Slaughter Station in west Texas to Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. Under provisions of the Omnibus Agreement with Holly we will have an option to purchase Holly’s investment in the project at a purchase price to be negotiated with Holly. The projects will increase the pipeline capacity between Lovington and Artesia by 40,000 bpd. The cost of the projects is expected to be $90.0 million and construction is currently expected to be completed and the projects to become fully operational in the fourth quarter of 2009.
We are currently working on a capital improvement project that will provide increased flexibility and capacity to our Intermediate Pipelines enabling us to accommodate increased volumes following Holly’s Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $5.1 million.
Also, we are currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline at an estimated cost of $1.9 million scheduled for completion in early 2009.

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We expect that our currently planned expenditures for maintenance capital as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline, SLC Pipeline, South System expansion and Holly crude oil projects described above will be funded with existing cash balances, cash generated by operations, the sale of additional limited partner units, the issuance of debt securities or advances under our $300.0 million senior secured revolving credit agreement maturing August 2011 (the “Credit Agreement”), or a combination thereof. With the current conditions in the credit and equity markets there may be limits on our ability to issue new debt or equity securities. Additionally, due to pricing in the current debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline and Holly’s crude oil project. We are not obligated to purchase these assets nor are we subject to any fees or penalties if HEP’s board of directors decide not to proceed with either of these opportunities.
SAFETY AND MAINTENANCE
We perform preventive and normal maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by code or regulation. We inject corrosion inhibitors into our mainlines to help control internal corrosion. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems.
We monitor the structural integrity of selected segments of our pipeline systems through a program of periodic internal inspections using both “dent pigs” and electronic “smart pigs”, as well as hydrostatic testing that conforms to federal standards. We follow these inspections with a review of the data and we make repairs as necessary to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. We believe this approach will ensure that the pipelines that have the greatest risk potential receive the highest priority in being scheduled for inspections or pressure tests for integrity. Our inspection process complies with all Department of Transportation (“DOT”) and Code of Federal Regulations 49 CFR Part 195 requirements.
Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state, and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT, and accepted industry practice.
At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.
Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals are subject to participation in a comprehensive environmental management program to assure compliance with applicable air, solid waste, and wastewater regulations.
COMPETITION
As a result of our physical integration with Holly’s Navajo and Woods Cross Refineries, our contractual relationship with Holly under the Omnibus Agreement and the three Holly pipelines and terminals

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agreements, we believe that we will not face significant competition for barrels of refined products transported from Holly’s Refineries, particularly during the term of the Holly PTA, Holly IPA and Holly CPTA expiring in 2019, 2020 and 2023, respectively. Additionally, with our contractual relationship with Alon under the Alon PTA, we believe that we will not face significant competition for those barrels of refined products we transport from Alon’s Big Spring Refinery, particularly during the term of our Alon PTA expiring in 2020.
However, we do face competition from other pipelines that may be able to supply the end-user markets of Holly or Alon with refined products on a more competitive basis. Additionally, If Holly’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.
The petroleum refining business is highly competitive. Among Holly’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. Holly competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.
Historically, the significant majority of the throughput at our terminal facilities has come from Holly, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso, and the Abilene and Wichita Falls terminals that serve Alon’s Big Springs Refinery. Under the terms of the Holly PTA and the Holly CPTA, we continue to receive a significant portion of the throughput at our terminal facilities from Holly.
Our ten refined product terminals compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location, price, versatility and services provided. Our competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms.
RATE REGULATION
Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and non-discriminatory. The Interstate Commerce Act permits challenges to rates that are already on file and in effect by complaint. A successful challenge under a complaint may result in the complainant obtaining damages or reparations for up to two years prior to the date the complaint was filed. The Interstate Commerce Act also permits challenges to a proposed new or changed rate by a protest. A successful challenge under a protest may result in the protestant obtaining refunds or reparations from the date the proposed new or changed rate was filed. In either challenge process, the third party must be able to show it has a substantial economic interest in those rates to proceed. The FERC generally has not investigated interstate rates on its own initiative but will likely become a party to any proceedings when the rates receive either a complaint or a protest. However, the FERC is not prohibited from bringing an interstate rate under investigation without a third party intervention.
While the FERC regulates the rates for interstate shipments on our refined product pipelines, the New Mexico Public Regulation Commission regulates the rates for intrastate shipments in New Mexico, the Texas Railroad Commission regulates the rates for intrastate shipments in Texas, and the Idaho Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State commissions have

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generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints, and we do not believe the intrastate tariffs now in effect are likely to be challenged. However, a state regulatory commission could investigate our rates if such a challenge were filed.
ENVIRONMENTAL REGULATION AND REMEDIATION
Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. Although these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.
We inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.
Under the Omnibus Agreement, Holly has also agreed to indemnify us up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to us and occurring or existing prior to the date of such transfers. The Omnibus Agreement provides environmental indemnification of up to $15.0 million through 2014 for the assets transferred to us at the time of our initial public offering in 2004 and up to $2.5 million through 2015 for the Intermediate Pipelines acquired in July 2005. In February 2008, Holly amended the Omnibus Agreement to provide an additional $7.5 million of indemnification through 2023 for environmental noncompliance and remediation liabilities specific to the Crude Pipelines and Tankage Assets.
Additionally, we have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon, for a ten year term expiring in 2015, will indemnify us subject to a $100,000 deductible and a $20.0 million maximum liability cap.
Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements.
In the third quarter of 2008, we discovered a crude oil leak on a section of pipeline recently acquired from Holly. We have initiated clean-up activities and have accrued $0.2 million for estimated future remediation costs.
There are additional environmental remediation projects that are currently in progress that relate to certain assets acquired from Holly. Certain of these projects were underway prior to our purchase and

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represent liabilities of Holly Corporation as the obligation for future remediation activities was retained by Holly. The remaining projects, including assessment and monitoring activities, are covered under the Holly environmental indemnification discussed above and also represent liabilities of Holly Corporation.
We may experience future releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although we maintain an extensive inspection and audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets, nevertheless, have the potential to substantially affect our business.
EMPLOYEES
To carry out our operations, HLS employs 121 people who provide direct support to our operations. Holly Logistic Services, L.L.C. considers its employee relations to be good. Neither we nor our general partner have employees. We reimburse Holly for direct expenses that Holly or its affiliates incurs on our behalf for the employees of HLS.
Item 1A. Risk Factors
Investing in us involves a degree of risk, including the risks described below. 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, results of operations or treatment of unitholders could be materially and adversely affected.
RISKS RELATED TO OUR BUSINESS
We depend upon Holly and particularly its Navajo Refinery for a majority of our revenues; if those revenues were significantly reduced or if Holly’s financial condition materially deteriorated, there would be a material adverse effect on our results of operations.
For the year ended December 31, 2008, Holly accounted for 72% of the revenues of our petroleum product and crude pipelines and 70% of the revenues of our terminals and truck loading racks. We expect to continue to derive a majority of our revenues from Holly for the foreseeable future. If Holly satisfies only its minimum obligations under the Holly PTA, Holly IPA and Holly CPTA or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at the Navajo Refinery or the Woods Cross Refinery, our revenues and cash flow would decline.
Any significant curtailing of production at the Navajo Refinery could, by reducing throughput in our pipelines and terminals, result in our realizing materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2008, production from the Navajo Refinery accounted for 67% of the throughput volumes transported by our refined product and crude pipelines. The Navajo Refinery also received 100% of the petroleum products shipped on our Intermediate Pipelines. Operations at the Navajo Refinery could be partially or completely shut down, temporarily or permanently, as the result of:
    competition from other refineries and pipelines that may be able to supply the refinery’s end-user markets on a more cost-effective basis;
 
    operational problems such as catastrophic events at the refinery, labor difficulties or environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at the refinery;
 
    planned maintenance or capital projects;

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    increasingly stringent environmental laws and regulations, such as the Environmental Protection Agency’s gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road usage as well as various state and federal emission requirements that may affect the refinery itself;
 
    an inability to obtain crude oil for the refinery at competitive prices; or
 
    a general reduction in demand for refined products in the area 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, higher taxes or stricter environmental laws or regulations; or
 
    a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation either mandating or encouraging higher fuel economy or the use of alternative fuel or otherwise.
The magnitude of the effect on us of any shutdown would depend on the length of the shutdown and the extent of the refinery operations affected by the shutdown. We have no control over the factors that may lead to a shutdown or the measures Holly may take in response to a shutdown. Holly makes all decisions at the Navajo Refinery concerning levels of production, regulatory compliance, refinery turnarounds (planned shutdowns of individual process units within the refinery to perform major maintenance activities), labor relations, environmental remediation and capital expenditures; is responsible for all related costs; and is under no contractual obligation to us to maintain operations at the Navajo Refinery.
Furthermore, Holly’s obligations under the Holly PTA and Holly IPA would be temporarily suspended during the occurrence of a force majeure that renders performance impossible with respect to an asset for at least 30 days. If such an event were to continue for a year, we or Holly could terminate the agreements. The occurrence of any of these events could reduce our revenues and cash flows.
We depend on Alon and particularly its Big Spring Refinery for a substantial portion of our revenues; if those revenues were significantly reduced, there would be a material adverse effect on our results of operations.
For the year ended December 31, 2008, Alon accounted for 16% of the combined revenues of our petroleum product and crude pipelines and of our terminals and truck loading racks, including revenues we received from Alon under a capacity lease agreement.
On February 18, 2008, Alon experienced an explosion and fire at its Big Spring refinery that resulted in the shutdown of production. In early April, Alon reopened its Big Spring refinery and resumed production at one-half of refinery capacity until late September when production was restored to full capacity. Lost production and reduced operations attributable to this incident resulted in a significant decrease in third party shipments and related revenues on our refined product pipelines during the first nine months of 2008. As a result of related contractual minimum commitments and resulting shortfall billings, the incidents did not materially affect our distributable cash flow.
Another decline in production at Alon’s Big Spring Refinery would materially reduce the volume of refined products we transport and terminal for Alon. As a result, our revenues would be materially adversely affected. The Big Spring Refinery could partially or completely shut down its operations, temporarily or permanently, due to factors affecting its ability to produce refined products or for planned maintenance or capital projects. Such factors would include the factors discussed above under the discussion of risk factors for the Navajo Refinery.
The magnitude of the effect on us of any shutdown depends on the length of the shutdown and the extent of the refinery operations affected. We have no control over the factors that may lead to a shutdown or

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the measures Alon may take in response to a shutdown. Alon makes all decisions and is responsible for all costs at the Big Spring Refinery concerning levels of production, regulatory compliance, refinery turnarounds, labor relations, environmental remediation and capital expenditures.
In addition, under the Alon PTA, if we are unable to transport or terminal refined products that Alon is prepared to ship, then Alon has the right to reduce its minimum volume commitment to us during the period of interruption. If a force majeure event occurs beyond the control of either of us, we or Alon could terminate the Alon pipelines and terminals agreement after the expiration of certain time periods. The occurrence of any of these events could reduce our revenues and cash flows.
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. As stated above, we receive substantial revenues from both Holly and Alon under their respective pipelines and terminals agreements. In addition, a subsidiary of BP Plc (“BP”) is our largest shipper on the Rio Grande Pipeline, a joint venture in which we own a 70% interest and from which we derived 8% of our revenues for the year ended December 31, 2008.
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.
Competition from other pipelines that may be able to supply our shippers’ customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.
We and our shippers could face increased competition if other pipelines are able to competitively supply our shippers’ end-user markets with refined products. The Longhorn Pipeline is a 72,000 bpd common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has put the pipeline up-for-sale. Although, Longhorn Partners Pipeline, L.P. did not complete a previously planned 72,000 bpd to 125,000 bpd capacity expansion project, a subsequent owner could resume and ultimately complete this planned expansion project under its own initiative. Increased supplies of refined product delivered by the Longhorn Pipeline and Kinder Morgan’s El Paso to Phoenix pipeline could result in additional downward pressure on wholesale refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from Holly and/or Alon. This could reduce our opportunity to earn revenues from Holly and Alon in excess of their minimum volume commitment obligations.
An additional factor that could affect some of Holly’s and Alon’s markets is excess pipeline capacity from the West Coast into our shippers’ Arizona markets on the pipeline from the West Coast to Phoenix. Additional increases in shipments of refined products from the West Coast into our shippers’ Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by Holly and Alon to these markets.
A material decrease in the supply, or a material increase in the price, of crude oil available to Holly’s and Alon’s refineries and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could materially reduce our revenues.
The volume of refined products we transport in our refined products pipelines depends on the level of production of refined products from Holly’s and Alon’s refineries, which, in turn, depends on the availability of attractively-priced crude oil produced in the areas accessible to those refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries, as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production

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declines or otherwise, could result in a decline in the volume of crude oil our shippers refine, absent the availability of transported crude oil to offset such declines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and therefore a corresponding reduction in our cash flow. In addition, the future growth of our shippers’ operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in their currently connected supplies.
Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline, or producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital. Similarly, a material increase in the price of crude oil supplied to our shippers’ refineries without an increase in the market value of the products produced by the refineries, either temporary or permanent, which caused a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, and our cash flow could be adversely affected.
Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations, any of which could reduce the demand for the petroleum products in the areas we serve.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing contracts 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 pipelines and the demand for refined products in the markets that we serve. Alon’s obligations to lease capacity on the Artesia-Orla-El Paso pipeline have remaining terms that expire beginning in 2012 through 2018. Our pipelines and terminals agreements with Holly and Alon expire beginning in 2019 through 2023. Additionally, Rio Grande executed a 5-year throughput agreement with PMI Trading Ltd. in January 2009 that expires 2014. This contract can be cancelled by either party following 180 days notice after June 30, 2011.
Our operations are subject to federal, state, and local laws and regulations relating to product quality specifications, environmental protection and operational safety that could require us to make substantial expenditures.
Our pipelines and terminal operations are subject to increasingly strict environmental and safety laws and regulations. Also, the transportation and storage of refined products produces a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. If we were to incur a significant liability pursuant to environmental laws or regulations, it could have a material adverse effect on us. We are also subject to the requirements of OSHA, and comparable state statutes. Any violation of OSHA could impose substantial costs on us.
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

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expenditures. There is growing consensus that some form of regulation will be forthcoming at the federal level in the United States with respect to greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides). Also, as a result of the U.S. Supreme Court’s decision in April 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our services. Furthermore, the costs of environmental and safety regulations are already significant and additional or more stringent regulation could increase these costs or could otherwise adversely affect our business.
Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products pipeline system could reduce or eliminate our ability to blend products.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and exclusions from coverage may limit our ability to recover the amount of the full loss in all situations. 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.
Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.
Holly, Alon and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals. For example, the common carrier pipelines used by Holly to serve the Arizona and Albuquerque markets are currently operated at or near capacity and are subject to proration. As a result, the volumes of refined product that Holly and other shippers have been able to deliver to these markets have been limited. The flow of additional products into El Paso for shipment to Arizona could further exacerbate such constraints on deliveries to Arizona. Any reduction in volumes transported in our pipelines or through our terminals could adversely affect our revenues and cash flows.
If our assumptions concerning population growth are inaccurate or if Holly’s growth strategy is not successful, our ability to grow may be adversely affected.

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Our growth strategy is dependent upon:
    the accuracy of our assumption that many of the markets that we currently serve or have plans to serve in the Southwestern and Rocky Mountain regions of the United States will experience population growth that is higher than the national average; and
 
    the willingness and ability of Holly to capture a share of this additional demand in its existing markets and to identify and penetrate new markets in the Southwestern and Rocky Mountain regions of the United States.
If our assumptions about growth in market demand prove incorrect, Holly may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy. Furthermore, Holly is under no obligation to pursue a growth strategy. If Holly chooses not to gain, or is unable to gain additional customers in new or existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth strategy would be adversely affected. Moreover, Holly may not make acquisitions that would provide acquisition opportunities to us; or, if those opportunities arise, they may not be financed by us or on terms attractive to us. Finally, Holly also will be subject to integration risks with respect to any new acquisitions it chooses to make.
Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.
One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. These projects may not be completed on schedule or at all or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, 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 facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
Rate regulation may not allow us to recover the full amount of increases in our costs.
The FERC regulates the tariff rates for interstate movements on our pipeline systems. The primary rate-making methodology of the FERC is price indexing. We use this methodology in all of our interstate markets. The indexing method allows a pipeline to increase its rates based on a percentage change in the producer price index for finished goods. If the index falls, we will be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing would adversely affect our revenues and cash flow.
If our interstate or intrastate tariff rates are successfully challenged, we could be required to reduce our tariff rates, which would reduce our revenues.
Under the FERC indexing methodology contained in the Code of Federal Regulations at 18 CFR 342-3, our interstate pipeline tariff rates are deemed just and reasonable. If a party with an economic interest were to file either a protest or a complaint against our tariff rates, or the FERC were to initiate an investigation of our rates, then our existing rates could be subject to detailed review. If our rates were found to be in excess of levels justified by our cost of service, the FERC could order us to reduce our rates, and to refund the amount by which the rates were determined to be excessive, plus interest. In

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addition, a state commission could also investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows if additional volumes and / or capacity are unavailable to offset such rate reductions.
Holly and Alon have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements. These agreements do not prevent other current or future shippers from challenging our tariff rates.
Potential changes to current petroleum pipeline rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future.
The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services. If the FERC’s petroleum pipeline rate-making methodology changes, the new methodology could result in tariffs that generate lower revenues and cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so.
The fees we charge to third parties under transportation and storage agreements may not escalate sufficiently to cover increases in our costs, and the agreements may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil or refined products is curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions and mechanical or physical failures of our equipment or facilities or those of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would be negatively impacted.
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 impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
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 leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

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As of December 31, 2008, the principal amount of our total outstanding debt was $385.0 million. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels. Various limitations in our Credit Agreement and the indenture for our Senior Notes may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
Our leverage could have important consequences. We will 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.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain beneficial transactions. The agreements governing our debt generally require us to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Additionally, our contribution agreements with Alon, and our purchase and contribution agreements with Holly with respect to the Intermediate Pipelines and the Crude Pipelines and Tankage Assets restrict us from selling the pipelines and terminals acquired from Alon or Holly, as applicable, and from prepaying more than $30.0 million of the Senior Notes until 2015 and any of the $171.0 million borrowed under the Credit Agreement for the purchase of the Crude Pipelines and Tankage assets until 2018, subject to certain limited exceptions. Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisitions, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including significant write-offs in the financial services sector and the current weak economic conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has 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 generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, 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

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acquisitions or announced and future pipeline construction projects, 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.
We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.
Our strategy contemplates growth through the development and acquisition of crude, intermediate and refined products transportation and storage assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in our chosen businesses and increase our market position.
We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.
In addition, we are experiencing increased competition for the types of assets and businesses we have historically purchased or acquired. Increased competition for a limited pool of assets could result in our losing to other bidders more often or acquiring assets at less attractive prices. Either occurrence would limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher distributions in the future.
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, 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.
We may be unsuccessful in integrating the operations 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. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly. 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

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different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions.
Due to our lack of asset diversification, adverse developments in our businesses could materially and adversely affect our financial condition, results of operations, or cash flows.
We rely exclusively on the revenues generated from our business. Due to our lack of asset diversification, an adverse development in our business could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.
We do not own all of the land on which our pipeline systems and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipeline systems and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the right to construct and operate pipelines on land owned by third parties and government agencies for specified periods of time. If we were to lose these rights through an inability to renew right-of-way contracts or otherwise, we may be required to relocate our pipelines and our business could be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, it may adversely affect our operations and cash flows available for distribution to unitholders.
Our business may suffer if any of our key senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our key senior executives and key senior employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks.
In certain cases we have the right to be indemnified by third parties for environmental liabilities, and our results of operation and our ability to make distributions to our unitholders could be adversely affected if a third party fails to satisfy an indemnification obligation owed to us.
In connection with our past acquisitions of pipelines, tankage, terminals and related assets from Holly and Alon, we have entered into environmental agreements with them pursuant to which they have agreed to indemnify us for certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition. These indemnities continue through 2014 for the assets contributed to us by Holly at our initial public offering, through 2015 for the Intermediate Pipelines acquired from Holly and the refined products pipelines, tankage and terminals acquired from Alon, and through 2023 for the Crude Pipelines and Tankage Assets acquired from Holly. Other third parties are also obligated to indemnify us for ongoing remediation pursuant to separate indemnification obligations. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected in the future if Holly, Alon, or other third parties fail to satisfy an indemnification obligation owed to us.
RISKS TO COMMON UNITHOLDERS
Holly and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.

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Currently, Holly indirectly owns the 2% general partner interest and a 44% limited partner interest in us and owns and controls our general partner, HEP Logistics Holdings, L.P. Conflicts of interest may arise between Holly and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following situations:
    Holly, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm’s-length, third-party transactions;
 
    neither our partnership agreement nor any other agreement requires Holly to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. Holly’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Holly;
 
    our general partner is allowed to take into account the interests of parties other than us, such as Holly, in resolving conflicts of interest;
 
    our general partner determines which costs incurred by Holly and its affiliates are reimbursable by us;
 
    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
    our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash available to us; and
 
    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with Holly.
Cost reimbursements, which will be determined by our general partner, and fees due our general partner and its affiliates for services provided, are substantial.
Under our Omnibus Agreement, we are currently obligated to pay Holly an administrative fee of $2.3 million per year for the provision by Holly or its affiliates of various general and administrative services for our benefit. The administrative fee may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from Holly or its affiliates. Our general partner will determine the amount of general and administrative expenses that will be properly allocated to us in accordance with the terms of our partnership agreement. In addition, our general partner and its affiliates are entitled to reimbursement for all other expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees of Holly Logistic Services, L.L.C. who provide services to us. Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf, plus the administrative fee. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we are charged fees as determined by our general partner.
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our

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general partner’s general partner and have no right to elect our general partner or the board of directors of our general partner’s general partner on an annual or other continuing basis. The board of directors of our general partner’s general partner is chosen by the members of our general partner’s general partner. Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Unitholders will be unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to prevent its removal. Also, if the general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner’s general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their respective partnership interests in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner of our general partner with their own choices and to control the decisions taken by the board of directors and officers.
We may issue additional common units without unitholder approval, which would dilute an existing unitholder’s ownership interests.
During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 3,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
    the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on an estimated pro forma basis;
 
    issuances of common units to repay indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the repayment of the indebtedness;

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    the conversion of subordinated units into common units;
 
    the conversion of units of equal rank with the common units into common units under some circumstances;
 
    in the event of a combination or subdivision of common units;
 
    issuances of common units under our employee benefit plans; or
 
    the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal or removal of our general partner.
The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
    our unitholders’ proportionate ownership interest in us will decrease;
 
    the amount of cash available for distribution on each unit may decrease;
 
    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
    the relative voting strength of each previously outstanding unit may be diminished; and
 
    the market price of the common units may decline,
After the end of the subordination period that is currently expected to end as of July 1, 2009, provided there is no significant decrease in our operating performance, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our` issuance of equity securities ranking junior to the common units at any time.
In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available to make the required payments to our debt holders or to pay the minimum quarterly distribution on our common units every quarter.
Holly and its affiliates may engage in limited competition with us.
Holly and its affiliates may engage in limited competition with us. Pursuant to the Omnibus Agreement among us, Holly and our general partner, Holly and its affiliates agreed not to engage in the business of operating intermediate or refined product pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. The Omnibus Agreement, however, does not apply to:
    any business operated by Holly or any of its subsidiaries at the closing of our initial public offering;

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    any business or asset that Holly or any of it subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5.0 million; and
any business or asset that Holly or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5.0 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so with the concurrence of our conflicts committee.
In the event that Holly or its affiliates no longer control our partnership or there is a change of control of Holly, the non-competition provisions of the omnibus agreement will terminate.
Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.
In some instances, our general partner may cause us to borrow funds from affiliates of Holly or from third parties in order to permit the payment of cash distributions.
These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions, or to hasten the expiration of the subordination period.
Our general partner has a limited call right that may require a holder of units to sell its common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, a holder of common units may be required to sell its units at an undesirable time or price and may not receive any return on its investment. A common unitholder may also incur a tax liability upon a sale of its units.
A unitholder may not have limited liability if a court finds that unitholder actions constitute control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.
In addition, Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
TAX RISKS TO COMMON UNITHOLDERS
Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our common units.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation, possibly on a retroactive basis. At the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. It could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to unitholders.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take on tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders are treated as partners to whom we allocate taxable income, which could be different in amount than the cash we distribute, they are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells its common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. A unitholder’s amount realized will be measured by the sum of the cash and the fair market value of other property, if any, received by the unitholder, plus its share of our nonrecourse liabilities. Because the amount realized will include the unitholder’s share of our

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nonrecourse liabilities, the gain recognized by the unitholder on the sale of its units could result in a tax liability in excess of any cash it receives from the sale. Distributions in excess of a unitholder’s allocable share of our net taxable income (“excess distributions”) decrease the unitholder’s tax basis in its common units, which includes its share of nonrecourse liabilities. Such excess distributions with respect to the units sold become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its original cost. Moreover, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, it would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, it may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a

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short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The reporting of partnership tax information is complicated and subject to audits.
We furnish each unitholder with a Schedule K-1 that sets forth the unitholder’s share of our income, gains, losses and deductions. We cannot guarantee that these schedules will be prepared in a manner that conforms in all respects to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, which could result in an audit of a unitholder’s individual tax return and increased liabilities for taxes because of adjustments resulting from the audit.
There are limits on the deductibility of our losses that may adversely affect our unitholders.
There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In the case of taxpayers subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a

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new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Texas, New Mexico, Arizona, Colorado, Utah, Idaho, Oklahoma and Washington. We may own property or conduct business in other states or foreign countries in the future. It is the unitholder’s responsibility to file all federal, state, local, and foreign tax returns.
Item 1B. Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
Item 2. Properties
PIPELINES
Our refined product pipelines transport light refined products from Holly’s Navajo Refinery in New Mexico and Alon’s Big Spring Refinery in Texas to their customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah, Oklahoma and northern Mexico. The refined products transported in these pipelines include conventional gasolines, federal, state and local specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that include high- and low-sulfur diesel and jet fuel and LPGs (such as propane, butane and isobutane).
Our intermediate product pipelines consist of two parallel pipelines that originate at Holly’s Lovington, New Mexico refining facilities and terminate at Holly’s Artesia, New Mexico refining facilities. These pipelines transport intermediate feedstocks and crude oil for Holly’s refining operations in New Mexico.
Our crude pipelines consist of crude oil trunk, gathering and connection pipelines located in west Texas and New Mexico that deliver crude oil to Holly’s Navajo Refinery and crude oil and refined product pipelines that support Holly’s Woods Cross Refinery.
Our pipelines are regularly inspected, are well maintained and we believe, are in good repair. Generally, other than as provided in the pipelines and terminal agreements with Holly and Alon, substantially all of our pipelines are unrestricted as to the direction in which product flows and the types of refined products that we can transport on them. The FERC regulates the transportation tariffs for interstate shipments on our refined product pipelines and state regulatory agencies regulate the transportation tariffs for intrastate shipments on our pipelines.
The following table details the average aggregate daily number of barrels of petroleum products transported on our pipelines in each of the periods set forth below for Holly and for third parties.

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    Years Ended December 31,
    2008(2)   2007   2006   2005(1)   2004
 
Volumes transported for (bpd):
                                       
Holly
    253,484       142,447       126,929       94,473       65,525  
Third parties (3)
    38,330       62,720       62,655       65,053       29,967  
 
                                       
Total
    291,814       205,167       189,584       159,526       95,492  
 
                                       
Total barrels in thousands (“mbbls”)
    106,804       74,886       69,198       58,227       34,950  
 
                                       
 
(1)   Includes volumes transported on the pipelines acquired from Alon on February 28, 2005, and volumes transported on the Intermediate Pipelines acquired on July 8, 2005.
 
(2)   Includes volumes transported on the Crude Pipelines acquired February 29, 2008.
 
(3)   Includes Rio Grande Pipeline volumes.
The following table sets forth certain operating data for each of our crude oil and petroleum product pipelines. Except as shown below, we own 100% of our pipelines. Throughput is the total average number of barrels per day transported on a pipeline, but does not aggregate barrels moved between different points on the same pipeline. Revenues reflect tariff revenues generated by barrels shipped from an origin to a delivery point on a pipeline. Revenues also include payments made by Alon under capacity lease arrangements on our Orla to El Paso pipeline. Under these arrangements, we provide space on our pipeline for the shipment of up to 17,500 barrels of refined product per day. Alon pays us whether or not it actually ships the full volumes of refined products it is entitled to ship. To the extent Alon does not use its capacity, we are entitled to use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of gasoline equivalent that may be transported in the existing configuration; in some cases, this includes the use of drag reducing agents.
                         
            Approximate    
            Length    
Origin and Destination   Diameter (inches)   (miles)   Capacity (bpd)
 
 
Refined Product Pipelines:
                       
Artesia, NM to El Paso, TX
    6       156       24,000  
Artesia, NM to Orla, TX to El Paso, TX
    8/12/8       215       70,000 (1)
Artesia, NM to Moriarty, NM(2)
    12/8       215       45,000 (3)
Moriarty, NM to Bloomfield, NM(2)
    8       191       (3)
Big Spring, TX to Abilene, TX
    6/8       105       20,000  
Big Spring, TX to Wichita Falls, TX
    6/8       227       23,000  
Wichita Falls, TX to Duncan, OK
    6       47       21,000  
Midland, TX to Orla, TX
    8/10       135       25,000  
Artesia, NM to Roswell, NM
    4       36       5,300  
Woods Cross, UT
    10/8       6       70,000  
Intermediate Product Pipelines:
                       
Lovington, NM to Artesia, NM
    8       65       48,000  
Lovington, NM to Artesia, NM
    10       65       72,000  
Crude Pipelines:
                       
Delivers to Holly’s Navajo Refinery
  Various     861          
Woods Cross, Utah
    12       4       40,000  
Rio Grande Pipeline Company:
                       
Rio Grande Pipeline(4)
    8       249       27,000  
 
(1)   Includes 17,500 bpd of capacity on the Orla to El Paso segment of this pipeline that is leased to Alon under capacity lease agreements.
 
(2)   The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and the Moriarty to Bloomfield pipeline is leased from Mid-America Pipeline Company, LLC (“Mid-America”) under a long-term lease agreement.
 
(3)   Capacity for this pipeline is reflected in the information for the Artesia to Moriarty pipeline.
 
(4)   We have a 70% joint venture interest in the entity that owns this pipeline that runs from West TX to El Paso, TX. Capacity reflects a 100% interest.
Holly shipped an aggregate of 68% of the petroleum products transported on our refined product pipelines and 100% of the petroleum products transported on our Intermediate Pipelines and Crude Oil pipelines in 2008. These pipelines transported approximately 95% of the light refined products produced by Holly’s Navajo Refinery in 2008.

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Artesia, New Mexico to El Paso, Texas
The Artesia to El Paso refined product pipeline is regulated by the FERC. It was constructed in 1959 and consists of 156 miles of 6-inch pipeline. This pipeline is used for the shipment of refined products produced at Holly’s Navajo Refinery to our El Paso terminal, where we deliver to common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s tank farm for truck rack loading for local delivery by tanker truck. The refined products shipped on this pipeline represented 14% of the total light refined products produced at Holly’s Navajo Refinery during 2008. Refined products produced at Holly’s Navajo Refinery destined for El Paso are transported on either this pipeline or our Artesia to Orla to El Paso pipeline.
Artesia, New Mexico to Orla, Texas to El Paso, Texas
The Artesia to Orla to El Paso refined product pipeline is a common-carrier pipeline regulated by the FERC and consists of three segments:
    an 8-inch, 9-mile and a 12-inch, 72-mile segment from Holly’s Navajo Refinery to Orla, Texas;
 
    a 12-inch, 126-mile segment from Orla to outside El Paso, Texas; and
 
    an 8-inch, 8-mile segment from outside El Paso to our El Paso terminal
There are two shippers on this pipeline, Holly and Alon. In 2008, this pipeline transported to our El Paso terminal 61% of the light refined products produced at Holly’s Navajo Refinery. As mentioned above, refined products destined to the El Paso terminal are delivered to common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s truck rack for local delivery by tanker truck.
At Orla, product is received into our tankage from Alon’s Big Spring Refinery via our FinTex Pipeline. These volumes are then sent from Orla to El Paso, either directly from the Artesia to Orla segment or from tankage in Orla.
Artesia, New Mexico to Moriarty, New Mexico
The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline from Holly’s Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White Lakes Junction to Moriarty segment of this pipeline and the Moriarty to Bloomfield pipeline described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered into in 1996, which expires in 2017 and has two ten-year extensions at our option. At our Moriarty terminal, volumes shipped on this pipeline can be transported to other markets in the area, including Albuquerque, Santa Fe and west Texas, via tanker truck. The 155-mile White Lakes Junction to Moriarty segment of this pipeline is operated by Mid-America (or its designee). Holly is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to adjustments based on changes in the PPI) of $513,000 to Mid-America to lease the White Lakes Junction to Moriarty and Moriarty to Bloomfield pipelines.
Moriarty, New Mexico to Bloomfield, New Mexico
The Moriarty to Bloomfield refined product pipeline was constructed in 1973 and consists of 191 miles of 8-inch pipeline leased from Mid-America. This pipeline serves our terminal in Bloomfield. At our Bloomfield terminal, volumes shipped on this pipeline are transported to other markets in the Four Corners area via tanker truck. This pipeline is operated by Mid-America (or its designee). Holly is the only shipper on this pipeline.
Big Spring, Texas to Abilene, Texas
The Big Spring to Abilene refined product pipeline was constructed in 1957 and consists of 100 miles of 6-inch pipeline and 5 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery to the Abilene terminal. Alon is the only shipper on this pipeline.

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Big Spring, Texas to Wichita Falls, Texas
Segments of the Big Spring to Wichita Falls refined product pipeline were constructed in 1969 and 1989, and consist of 95 miles of 6-inch pipeline and 132 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery to the Wichita Falls terminal. Alon is the only shipper on this pipeline.
Wichita Falls, Texas to Duncan, Oklahoma
The Wichita Falls to Duncan refined product pipeline is a common carrier and is regulated by the FERC. It was constructed in 1958 and consists of 47 miles of 6-inch pipeline. This pipeline is used for the shipment of refined products from the Wichita Falls terminal to Alon’s Duncan terminal, which we do not own. Alon is the only shipper on this pipeline.
Midland, Texas to Orla, Texas
Segments of the Midland to Orla refined product pipeline were constructed in 1928 and 1998, and consist of 50 miles of 10-inch pipeline and 85 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery from Midland to our tank farm at Orla. Alon is the only shipper on this pipeline.
Artesia, New Mexico to Roswell, New Mexico
The 36-mile 4-inch diameter Artesia to Roswell refined product pipeline delivers jet fuel only to tanks located at our jet fuel terminal in Roswell. Holly is the only shipper on this pipeline.
Woods Cross, Utah refined product pipelines
The Woods Cross refined products pipelines consist of three pipeline segments. The Woods Cross to Pioneer Terminal segment consists of 2 miles of 8-inch pipeline and is used for product shipments to and through the Pioneer Terminal. The Woods Cross to Pioneer segment represents 2 miles of 10-inch pipeline that is also used for product shipments to and through the Pioneer Terminal. The Woods Cross to Chevron Pipeline’s Salt Lake Products Pipeline segment consists of 4 miles of 8-inch pipeline and is used for product shipments from the Woods Cross Refinery to Chevron’s North Salt Lake pumping station. Holly is the only shipper on these pipelines.
8” Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile 8-inch diameter pipeline was constructed in 1981. This pipeline is used for the shipment of intermediate feedstocks, crude oil and LPGs from Holly’s Lovington facility to its Artesia facility.
10” Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile 10-inch diameter pipeline was constructed in 1999. This pipeline is used for the shipment of intermediate feedstocks and crude oil from Holly’s Lovington facility to its Artesia facility. Holly is the only shipper on this pipeline.
Crude Oil Pipelines that deliver to Holly’s Navajo Refinery
The crude oil mainline gathering and mainline pipelines deliver crude oil to Holly’s Navajo Refinery and consists of 850 miles of 4-inch and 6-inch diameter pipeline and 450,000 barrels of crude oil tankage. The crude oil mainline pipelines consists of five pipeline segments that deliver crude oil to the Navajo Lovington facility and eight pipeline segments that deliver crude oil to the Navajo Artesia facility.
The Lovington system crude oil mainlines include five pipeline segments consisting of a 23-mile 12-inch pipeline from Russell to Lovington, a 20-mile 8-inch pipeline from Russell to Hobbs, an 11-mile 6-inch and 8-inch pipeline from Crouch to Lovington, a 20-mile 8-inch pipeline from Hobbs to Lovington and a 6-mile 6-inch pipeline from Gaines to Jobs.
The Artesia system crude oil mainlines include eight pipeline segments consisting of an 11-mile 6-inch pipeline from Beeson to North Artesia, a 7-mile 4-inch and 6-inch pipeline from Barnsdall to North Artesia, a 2-mile 8-inch pipeline from the Barnsdall jumper line to Lovington, a 4-mile 4-inch pipeline from the Artesia Station to North Artesia, a 6-mile 8-inch pipeline from North Artesia to Evans Junction, a 1-mile 6-inch pipeline from Abo to Evans Junction and a 12-mile 8-inch pipeline from Evans Junction to Artesia.

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Woods Cross, Utah crude oil pipeline
This 4-mile 12-inch pipeline is used for the shipment of crude oil from Chevron Pipe Line’s North Salt Lake City station to Holly’s Woods Cross Refinery.
Rio Grande Pipeline
We own a 70% interest in Rio Grande, a joint venture that owns a 249-mile, 8-inch common carrier LPG pipeline regulated by the FERC. The other owner of Rio Grande is a subsidiary of BP. The pipeline originates from a connection with an Enterprise pipeline in west Texas at Lawson Junction, which serves as its primary receipt point, although there is an additional receipt point near Midland, Texas. The pipeline terminates at the Mexico border near San Elizario, Texas. The pipeline transports LPGs for ultimate use by Petróleos Mexicanos (PEMEX, the government-owned energy company of Mexico.) Rio Grande does not own any facilities or pipelines in Mexico. The pipeline has a current capacity of approximately 27,000 bpd. This pipeline was originally constructed in the mid 1950’s, was first reconditioned in 1988, and subsequently reconditioned in 1996 and 2003. Approximately 75 miles of this pipeline has been replaced with new pipe, and an additional 50 miles has been recoated.
Currently, only LPG’s are transported on this pipeline. In January 2009, Rio Grande executed a 5-year throughput agreement with PMI Trading Ltd. that provides for the shipment of a minimum average of 16,000 bpd of LPG’s during the term of the agreement. The tariff rates and shipping regulations are regulated by the FERC. In January 2005, Rio Grande appointed us as operator of the pipeline system effective April 1, 2005 through January 31, 2010. As operator, we receive a management fee of $1.3 million per year, adjusted annually for any changes in the PPI.
An officer of HLS is one of the two members of Rio Grande’s management committee.
REFINED PRODUCT TERMINALS, TRUCK RACKS AND REFINERY CRUDE OIL TANKAGE
Refined Product Terminals and Truck Racks
Our refined product terminals receive products from pipelines connected to Holly’s Navajo and Woods Cross Refineries and Alon’s Big Spring Refinery. We then distribute them to Holly and third parties, who in turn deliver them to end-users and retail outlets. Our terminals are generally complementary to our pipeline assets and serve Holly’s and Alon’s marketing activities. Terminals play a key role in moving product to the end-user market by providing the following services:
    distribution;
 
    blending to achieve specified grades of gasoline;
 
    other ancillary services that include the injection of additives and filtering of jet fuel; and
 
    storage and inventory management.
Typically, our refined product terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that operates 24 hours a day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by our customers. In addition, nearly all of our terminals are equipped with truck loading racks capable of providing automated blending to individual customer specifications.
Our refined product terminals derive most of their revenues from terminalling fees paid by customers. We charge a fee for transferring refined products from the terminal to trucks or to pipelines connected to the terminal. In addition to terminalling fees, we generate revenues by charging our customers fees for blending, injecting additives, and filtering jet fuel. Holly currently accounts for the substantial majority of our refined product terminal revenues.

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The table below sets forth the total average throughput for our refined product terminals in each of the periods presented:
                                         
    Years Ended December 31,
    2008   2007   2006   2005(1)   2004
 
 
                                       
Refined products terminalled for (bpd):
                                       
Holly
    109,539       119,910       118,202       120,795       114,991  
Third parties
    32,737       45,457       43,285       42,334       24,821  
 
                                       
Total
    142,276       165,367       161,487       163,129       139,812  
 
                                       
Total (mbbls)
    52,073       60,359       58,943       59,542       51,171  
 
                                       
 
(1)   Includes volumes for the terminals and tank farm acquired from Alon February 28, 2005.
The following table outlines the locations of our terminals and their storage capacities, number of tanks, supply source, and mode of delivery:
                         
            Number        
    Storage Capacity   of   Supply    
Terminal Location   (barrels)   Tanks   Source   Mode of Delivery
 
El Paso, TX
    507,000       16     Pipeline/ rail   Truck/Pipeline
Moriarty, NM
    189,000       9     Pipeline   Truck
Bloomfield, NM
    193,000       7     Pipeline   Truck
Tucson, AZ(1)
    176,000       9     Pipeline   Truck
Mountain Home, ID(2)
    120,000       3     Pipeline   Pipeline
Boise, ID(3)
    111,000       9     Pipeline   Pipeline
Burley, ID(3)
    70,000       7     Pipeline   Truck
Spokane, WA
    333,000       32     Pipeline/Rail   Truck
Abilene, TX
    127,000       5     Pipeline   Truck/Pipeline
Wichita Falls, TX
    220,000       11     Pipeline   Truck/Pipeline
Roswell, NM (2)
    25,000       1     Pipeline   Truck
Orla tank farm
    135,000       5     Pipeline   Pipeline
Artesia facility truck rack
    N/A       N/A     Refinery   Truck
Woods Cross facility truck rack
    N/A       N/A     Refinery   Truck/Pipeline
 
                       
Total
    2,206,000                  
 
                       
 
(1)   The underlying ground at the Tucson terminal is leased.
 
(2)   Handles only jet fuel.
 
(3)   We have a 50% ownership interest in these terminals. The capacity and throughput information represents the proportionate share of capacity and throughput attributable to our ownership interest.
El Paso Terminal
We receive light refined products at this terminal from Holly’s Artesia facility through our Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account for approximately 97% of the volumes at this terminal. We also receive product from Alon’s Big Spring Refinery that accounted for 3% of the volumes at this terminal in 2008. Refined products received at this terminal are sold locally via the truck rack or transported to our Tucson terminal and other terminals in Phoenix on Kinder Morgan’s East System pipeline. Competition in this market includes a refinery and terminal owned by Western Refining, Inc., a joint venture pipeline and terminal owned by ConocoPhillips and NuStar Energy, L.P. (“NuStar”) and a terminal connected to the Longhorn Pipeline.
Moriarty Terminal
We receive light refined products at this terminal from Holly’s Artesia facility through our pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly is our only customer at this terminal. There are no competing terminals in Moriarty.
Bloomfield Terminal
We receive light refined products at this terminal from Holly’s Artesia facility through our pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly is our only customer at this terminal. Competition in this market includes a refinery and truck loading rack owned by Western Refining, Inc.

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Tucson Terminal
We own 100% of the improvements and lease underlying ground at this terminal. The Tucson terminal receives light refined products from Kinder Morgan’s East System pipeline, which transports refined products from Holly’s Artesia facility that it receives at our El Paso terminal. Refined products received at this terminal are sold locally, via the truck rack. Competition in this market includes terminals owned by Kinder Morgan and CalJet.
Mountain Home Terminal
We receive jet fuel from third parties at this terminal that is transported on Chevron’s Salt Lake City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal through our 13-mile, 4-inch pipeline to the United States Air Force base outside of Mountain Home. Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air base. We are paid a single fee, from the Defense Energy Support Center, for injecting, storing, testing and transporting jet fuel at this terminal.
Boise Terminal
We and Sinclair Transportation Company (“Sinclair’) each own a 50% interest in the Boise terminal. Sinclair is the operator of the terminal. The Boise terminal receives light refined products from Holly and Sinclair shipped through Chevron’s pipeline originating in Salt Lake City, Utah. The Woods Cross Refinery, as well as other refineries in the Salt Lake City area, and Pioneer Pipeline Co.’s terminal in Salt Lake City are connected to the Chevron pipeline. All loading of products out of the Boise terminal is conducted at Chevron’s loading rack, which is connected to the Boise terminal by pipeline. Holly and Sinclair are the only customers at this terminal.
Burley Terminal
We and Sinclair each own a 50% interest in the Burley terminal. Sinclair is the operator of the terminal. The Burley terminal receives product from Holly and Sinclair shipped through Chevron’s pipeline originating in Salt Lake City, Utah. Refined products received at this terminal are sold locally, via the truck rack. Holly and Sinclair are the only customers at this terminal.
Spokane Terminal
This terminal is connected to the Woods Cross Refinery via a Chevron common carrier pipeline. The Spokane terminal also is supplied by Chevron and Yellowstone pipelines and by rail and truck. Refined products received at this terminal are sold locally, via the truck rack. We have several major customers at this terminal. Other terminals in the Spokane area include terminals owned by ExxonMobil and ConocoPhillips.
Abilene Terminal
This terminal receives refined products from Alon’s Big Spring Refinery, which accounted for all of its volumes in 2008. Refined products received at this terminal are sold locally via a truck rack or pumped over a 2-mile pipeline to Dyess Air Force Base. Alon is the only customer at this terminal.
Wichita Falls Terminal
This terminal receives refined products from Alon’s Big Spring Refinery, which accounted for all of its volumes in 2008. Refined products received at this terminal are sold via a truck rack or shipped via pipeline connections to Alon’s terminal in Duncan, Oklahoma and also to NuStar’s Southlake Pipeline. Alon is the only customer at this terminal.
Roswell Terminal
This terminal receives jet fuel from Holly’s Navajo Refinery, which accounted for all of its volumes in 2008, for further transport to Cannon Air Force Base and to Albuquerque, New Mexico. We lease this terminal under an agreement that expires in September 2011.
Orla Tank Farm
The Orla tank farm was constructed in 1998. It receives refined products from Alon’s Big Spring Refinery that accounted for all of its volumes in 2008. Refined products received at the tank farm are delivered into our Orla to El Paso pipeline. Alon is the only customer at this tank farm.

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Artesia Facility Truck Rack
The truck rack at Holly’s Artesia facility loads light refined products, produced at the facility, onto tanker trucks for delivery to markets in the surrounding area. Holly is the only customer of this truck rack.
Woods Cross Facility Truck Rack
The truck rack at Holly’s Woods Cross facility loads light refined products produced at Holly’s Woods Cross Refinery onto tanker trucks for delivery to markets in the surrounding area. Holly is the only customer of this truck rack. Holly also makes transfers to a common carrier pipeline at this facility.
Refinery Crude Oil Tankage
Our refinery tankage consists of on-site crude oil tankage at Holly’s Navajo and Woods Cross Refineries. Our refinery tankage derives its revenues from fixed fees charged in providing the Holly’s refining facilities with approximately 600,000 barrels per month of crude storage.
The following table outlines the locations of our refinery crude oil tankage, storage capacity and number of tanks:
                 
    Storage   Number
    Capacity   of
Refinery Location   (barrels)   Tanks
 
Artesia , NM
    166,000       2  
Lovington, NM
    267,000       2  
Woods Cross, UT
    180,000       3  
 
               
Total
    613,000          
 
               
TRUCK FLEET
We have a truck fleet consisting of 7 trucks and 13 trailers that transport crude oil to Holly’s Wood Cross Refinery. Our trucking operations are conducted in Utah only and Holly is our only customer.
PIPELINE AND TERMINAL CONTROL OPERATIONS
All of our pipelines are operated via geosynchronous satellite, microwave, radio and frame relay communication systems from our central control room located in Artesia, New Mexico. We also monitor activity at our terminals from this control room.
The control center operates with state-of-the-art System Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points on the pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces our requirement for full-time on-site personnel at most of these locations.
Item 3. Legal Proceedings
We are a party to various legal and regulatory proceedings, which we believe will not have a material adverse impact on our financial condition, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2008.

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PART II
Item 5.   Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Our common limited partner units are traded on the New York Stock Exchange under the symbol “HEP.” The following table sets forth the range of the daily high and low sales prices per common unit, cash distributions to common unitholders and the trading volume of common units for the period indicated.
                                 
                    Cash   Trading
Years Ended December 31,   High   Low   Distributions   Volume
2008
                               
Fourth Quarter
  $ 33.46     $ 14.93     $ 0.755       3,901,900  
Third Quarter
  $ 39.16     $ 26.01     $ 0.745       2,537,800  
Second Quarter
  $ 47.03     $ 37.33     $ 0.735       1,914,000  
First Quarter
  $ 44.23     $ 36.06     $ 0.725       1,384,400  
 
2007
                               
Fourth Quarter
  $ 48.09     $ 42.04     $ 0.715       1,065,300  
Third Quarter
  $ 57.24     $ 43.10     $ 0.705       1,273,100  
Second Quarter
  $ 56.69     $ 46.55     $ 0.690       1,231,600  
First Quarter
  $ 49.97     $ 39.50     $ 0.675       948,900  
A distribution for the quarter ended December 31, 2008 of $0.765 per unit is payable on February 13, 2009.
As of February 6, 2009, we had approximately 5,720 common unitholders, including beneficial owners of common units held in street name.
We consider cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our revolving credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in the Credit Agreement, occurs or would result from the cash distribution. The indenture relating to our 6.25% senior notes prohibits us from making cash distributions under certain circumstances.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter: less the amount of cash reserves established by our general partner to provide for the proper conduct of our business; comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
Upon the closing of our initial public offering, Holly received 7,000,000 subordinated units. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period extends until the first day of any quarter beginning after June 30, 2009 that certain tests based on our exceeding minimum quarterly distributions are met. That period is currently expected to end as of July 1, 2009.

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We issued 937,500 of our Class B subordinated units in connection with the Alon transaction in 2005. The Class B subordinated units issued to Alon vote as a single class and rank equally with our existing subordinated units. There is a subordination period with respect to the Class B subordinated units with generally similar provisions to the subordinated units held by Holly, except that the subordination period will end on the last day of any quarter ending on or after March 31, 2010 if Alon has not defaulted on its minimum volume commitment payment obligations for the three consecutive, non-overlapping four quarter periods immediately preceding that date, subject to certain grace periods. If Holly is removed as the general partner without cause, the subordination period for the Class B subordinated units may end before March 31, 2010.
We make distributions of available cash from operating surplus for any quarter during any subordination period in the following manner: first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.
The general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
                         
            Marginal Percentage Interest in
    Total Quarterly Distribution   Distributions
    Target Amount   Unitholders   General Partner
Minimum Quarterly Distribution
  $ 0.50       98 %     2 %
First Target Distribution
  Up to $0.55     98 %     2 %
Second Target Distribution
  above $0.55 up to $0.625     85 %     15 %
Third Target distribution
  above $0.625 up to $0.75     75 %     25 %
Thereafter
  Above $0.75     50 %     50 %

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Item 6. Selected Financial Data
The following table shows selected financial information for HEP. This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of HEP and related notes thereto included elsewhere in this Form 10-K. See “Historical Results of Operations” below for a description of factors affecting the comparability of our financial information for 2004.
                                                         
                                    2004  
                                    Combined     Successor     Predecessor  
                                            July 13, 2004     January 1, 2004  
    Year Ended     Year Ended     Year Ended     Year Ended     Year Ended     Through     Through  
    December 31,     December 31,     December 31,     December 31,     December 31,     December 31,     July 12,  
    2008     2007     2006     2005     2004(1)     2004     2004  
    (In thousands, except per unit data)  
Statement Of Income Data:
                                                       
 
Revenue
  $ 118,088     $ 105,407     $ 89,194     $ 80,120     $ 67,766     $ 28,182     $ 39,584  
Operating costs and expenses
                                                       
Operations
    41,270       32,911       28,630       25,332       23,641       10,104       13,537  
Depreciation and amortization
    22,889       14,382       15,330       14,201       7,224       3,241       3,983  
General and administrative
    6,377       5,043       4,854       4,047       1,860       1,859       1  
 
                                         
 
    70,536       52,336       48,814       43,580       32,725       15,204       17,521  
 
                                       
 
Operating income
    47,552       53,071       40,380       36,540       35,041       12,978       22,063  
 
Interest income
    159       533       899       649       144       65       79  
Interest expense
    (21,763 )     (13,289 )     (13,056 )     (9,633 )     (697 )     (697 )      
Gain on sale of assets
    36       298                                
Other income
    996                                      
Minority interest in Rio Grande Pipeline Company
    (1,278 )     (1,067 )     (680 )     (740 )     (1,994 )     (956 )     (1,038 )
 
                                         
 
    (21,850 )     (13,525 )     (12,837 )     (9,724 )     (2,547 )     (1,588 )     (959 )
 
                                         
 
Income before income taxes
    25,702       39,546       27,543       26,816       32,494       11,390       21,104  
 
State income tax
    (335 )     (275 )                              
 
                                         
 
Net income
    25,367       39,271       27,543       26,816       32,494       11,390       21,104  
 
Less:
                                                       
Net income attributable to Predecessor
                            21,104             21,104  
General partner interest in net income, including incentive distributions(2)
    3,543       2,932       1,710       721       228       228        
 
                                         
Limited partners’ interest in net income
  $ 21,824     $ 36,339     $ 25,833     $ 26,095     $ 11,162     $ 11,162     $  
 
                                         
Net income per limited partner unit — basic and diluted(2)
  $ 1.34     $ 2.26     $ 1.60     $ 1.70             $ 0.80          
 
                                             
Cash distributions declared per unit applicable to limited partners
  $ 2.96     $ 2.785     $ 2.585     $ 2.225             $ 0.435          
 
                                             
 
                                                       
Other Financial Data:
                                                       
EBITDA (3)
  $ 70,195     $ 66,684     $ 55,030     $ 50,001     $ 40,271     $ 15,263     $ 25,008  
Distributable cash flow(4)
  $ 60,365     $ 51,012     $ 47,219     $ 42,451     $ 38,687     $ 14,492     $ 24,195  
Cash flows from operating activities
  $ 63,651     $ 59,056     $ 45,853     $ 42,628     $ 15,867     $ 15,371     $ 496  
Cash flows from investing activities
  $ (213,267 )   $ (9,632 )   $ (9,107 )   $ (131,795 )   $ (2,977 )   $ (305 )   $ (2,672 )
Cash flows from financing activities
  $ 144,564     $ (50,658 )   $ (45,774 )   $ 90,646     $ (480 )   $ 1,770     $ (2,250 )
Maintenance capital expenditures (5)
  $ 3,133     $ 1,863     $ 1,095     $ 364     $ 1,197     $ 305     $ 892  
Expansion capital expenditures
    39,170       8,094       8,012       3,519       1,780             1,780  
 
                                         
Total capital expenditures
  $ 42,303     $ 9,957     $ 9,107     $ 3,883     $ 2,977     $ 305     $ 2,672  
 
                                         
 
                                                       
Balance Sheet Data (at period end):
                                                       
Net property, plant and equipment
  $ 290,284     $ 158,600     $ 160,484     $ 162,298     $ 74,626     $ 74,626     $ 95,337  
Total assets
  $ 439,688     $ 238,904     $ 245,771     $ 254,775     $ 103,758     $ 103,758     $ 156,373  
Long-term debt
  $ 355,793     $ 181,435     $ 180,660     $ 180,737     $ 25,000     $ 25,000     $  
Total liabilities
  $ 431,568     $ 200,348     $ 198,582     $ 190,962     $ 28,998     $ 28,998     $ 53,146  
Net partners’ equity (deficit) (6)
  $ (2,098 )   $ 27,816     $ 36,226     $ 52,060     $ 61,528     $ 61,528     $ 89,964  

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(1)   Combined results for the year ended December 31, 2004 is not a calculation based upon U.S. generally accepted accounting principles (“GAAP”), and is presented here to provide investors with additional information for comparing year-over-year information.
 
(2)   Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes any incentive distributions declared in the period. The net income applicable to the limited partners is divided by the weighted average limited partner units outstanding in computing the net income per unit applicable to limited partners.
 
(3)   Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income plus (i) interest expense net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon 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 compliance with financial covenants.
 
    Set forth below is our calculation of EBITDA.
                                                         
                                    2004  
                                    Combined     Successor     Predecessor  
                                            July 13, 2004     January 1, 2004  
    Year Ended     Year Ended     Year Ended     Year Ended     Year Ended     Through     Through  
    December 31,     December 31,     December 31,     December 31,     December 31,     December 31,     July 12,  
    2008     2007     2006     2005     2004     2004     2004  
    (In thousands)  
 
                                                       
Net income
  $ 25,367     $ 39,271     $ 27,543     $ 26,816     $ 32,494     $ 11,390     $ 21,104  
 
                                                       
Add interest expense
    18,479       12,281       12,088       8,848       531       531        
Add amortization of discount and deferred debt issuance costs
    1,002       1,008       968       785       166       166        
Change in fair value — interest rate swaps
    2,282                                      
Subtract interest income
    (159 )     (533 )     (899 )     (649 )     (144 )     (65 )     (79 )
Add state income tax
    335       275                                
Add depreciation and amortization
    22,889       14,382       15,330       14,201       7,224       3,241       3,983  
 
                                         
 
EBITDA
  $ 70,195     $ 66,684     $ 55,030     $ 50,001     $ 40,271     $ 15,263     $ 25,008  
 
                                         
 
(4)   Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or 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. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

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    Set forth below is our calculation of distributable cash flow
                                                         
                                    2004  
                                    Combined     Successor     Predecessor  
                                            July 13, 2004     January 1, 2004  
    Year Ended     Year Ended     Year Ended     Year Ended     Year Ended     Through     Through  
    December 31,     December 31,     December 31,     December 31,     December 31,     December 31,     July 12,  
    2008     2007     2006     2005     2004     2004     2004  
    (In thousands)  
 
                                                       
Net income
  $ 25,367     $ 39,271     $ 27,543     $ 26,816     $ 32,494     $ 11,390     $ 21,104  
 
                                                       
Add amortization of discount and deferred debt issuance costs
    1,002       1,008       968       785       166       166        
Add change in fair value — interest rate swaps
    2,282                                      
Add depreciation and amortization
    22,889       14,382       15,330       14,201       7,224       3,241       3,983  
Add (subtract) increase (decrease) in deferred revenue
    11,958       (1,786 )     4,473       1,013                    
Subtract maintenance capital expenditures(5)
    (3,133 )     (1,863 )     (1,095 )     (364 )     (1,197 )     (305 )     (892 )
 
                                         
Distributable cash flow
  $ 60,365     $ 51,012     $ 47,219     $ 42,451     $ 38,687     $ 14,492     $ 24,195  
 
                                         
 
(5)   Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets in order to maintain the operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety and to address environmental regulations.
 
(6)   As a master limited partnership, we distribute our available cash, which historically has exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004 and the intermediate pipelines purchased from Holly in 2005 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $157.3 million would have been recorded as increases to our properties and equipment and intangible assets instead of reductions to our partners’ equity.
Historical Results of Operations
Prior to the commencement of HEP operations on July 13, 2004, our historical financial data does not reflect any general and administrative expenses as Holly did not historically allocate any of its general and administrative expenses to its pipelines and terminals. Our historical results of operations prior to July 13, 2004 include costs associated with crude oil and intermediate product pipelines, which were not contributed to our partnership.
NPL constitutes HEP’s predecessor. The transfer of ownership of assets from NPL to HEP on July 13, 2004 represented a reorganization of entities under common control and was recorded at NPL’s historical cost. Accordingly, our historical results of operations include the results of NPL prior to the transfer to HEP.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Item 7, including but not limited to the sections on “Liquidity and Capital Resources”, contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I. In this document, the words “we”, “our”, “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.
OVERVIEW
HEP is a Delaware limited partnership. We own and operate substantially all of the petroleum product and crude oil pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande. Holly currently owns a 46% interest in us.
We operate a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho and Washington. We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport or terminal; therefore, we are not directly exposed to changes in commodity prices.
On February 29, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly for $180.0 million. The Crude Pipelines and Tankage Assets primarily consist of crude oil trunk lines and gathering lines, product and crude oil pipelines and tankage that service Holly’s Navajo and Woods Cross Refineries and a leased jet fuel terminal. Please read “Holly Crude Pipelines and Tankage Transaction” under “Liquidity and Capital Resources” for additional information on this transaction.
Agreements with Holly Corporation and Alon
We serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline, terminal and tankage agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.
We have an agreement, the Holly PTA, that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering in 2004 and expires in 2019. Our second agreement, the Holly IPA, relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020. Our third agreement, the Holly CPTA, relates to the Crude Pipelines and Tankage Assets acquired from Holly as discussed above and expires in February 2023.
Under these agreements, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or FERC index, but 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 which is reviewed periodically.
We also have a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

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At December 31, 2008, contractual minimums under our long-term service agreements are as follows:
                         
    Minimum
Annualized
             
    Commitment              
Agreement   (In millions)     Year of Maturity   Contract Type
 
Holly PTA
  $ 41.2       2019     Minimum revenue commitment
Holly IPA
    13.3       2020     Minimum revenue commitment
Holly CPTA
    26.8       2023     Minimum revenue commitment
Alon PTA
    22.0       2020     Minimum volume commitment
Alon capacity lease
    6.8     Various       Capacity lease
 
                     
 
                       
Total
  $ 110.1                  
 
                     
We depend on our agreements with Holly and Alon for the majority of our revenues. A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso, Texas (the “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 our 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. Currently, we expect to complete the majority of this project in early 2009.
Under certain provisions of the Omnibus Agreement that we entered into with Holly in July 2004 and expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Effective March 1, 2008, the annual fee was increased from $2.1 million to $2.3 million to cover additional general and administrative services attributable to the operations of our Crude Pipelines and Tankage Assets. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.
Please read “Agreements with Holly” under Item 1, “Business” for additional information on these agreements with Holly and Alon.

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RESULTS OF OPERATIONS
The following tables present our operating income, volume information and cash flow summary information for the years ended December 31, 2008, 2007 and 2006.
                         
           
    Year Ended        
    December 31,     Change from  
    2008     2007     2007  
    (In thousands, except per unit data)  
Revenues
                       
Pipelines:
                       
Affiliates — refined product pipelines
  $ 40,446     $ 36,281     $ 4,165  
Affiliates — intermediate pipelines
    11,917       13,731       (1,814 )
Affiliates — crude pipelines
    22,380             22,380  
 
                 
 
    74,743       50,012       24,731  
Third parties — refined product pipelines
    28,580       36,271       (7,691 )
 
                 
 
    103,323       86,283       17,040  
 
                       
Terminals and truck loading racks:
                       
Affiliates
    10,297       10,949       (652 )
Third parties
    4,468       5,427       (959 )
 
                 
 
    14,765       16,376       (1,611 )
 
                       
Other — affiliates
          2,748       (2,748 )
 
                 
 
                       
Total revenues
    118,088       105,407       12,681  
 
                       
Operating costs and expenses
                       
Operations
    41,270       32,911       8,359  
Depreciation and amortization
    22,889       14,382       8,507  
General and administrative
    6,377       5,043       1,334  
 
                 
 
    70,536       52,336       18,200  
 
                 
 
                       
Operating income
    47,552       53,071       (5,519 )
 
                       
Interest income
    159       533       (374 )
Interest expense, including amortization
    (21,763 )     (13,289 )     (8,474 )
Gain on sale of assets
    36       298       (262 )
Other income
    996             996  
Minority interest in Rio Grande Pipeline Company
    (1,278 )     (1,067 )     (211 )
 
                 
 
    (21,850 )     (13,525 )     (8,325 )
 
                 
 
                       
Income before income taxes
    25,702       39,546       (13,844 )
 
                       
State income tax
    (335 )     (275 )     (60 )
 
                 
 
                       
Net income
    25,367       39,271       (13,904 )
 
                       
Less general partner interest in net income, including incentive distributions (1)
    3,543       2,932       611  
 
                 
 
                       
Limited partners’ interest in net income
  $ 21,824     $ 36,339     $ (14,515 )
 
                 
 
                       
Net income per unit applicable to limited partners (1)
  $ 1.34     $ 2.26     $ (0.92 )
 
                 
 
                       
Weighted average limited partners’ units outstanding
    16,291       16,108       183  
 
                 
 
                       
EBITDA(2)
  $ 70,195     $ 66,684     $ 3,511  
 
                 
 
                       
Distributable cash flow (3)
  $ 60,365     $ 51,012     $ 9,353  
 
                 
 
                       
Volumes (bpd)(4)
                       
Pipelines:
                       
Affiliates — refined product pipelines
    83,203       77,441       5,762  
Affiliates — intermediate pipelines
    58,855       65,006       (6,151 )
Affiliates — crude pipelines
    111,426             111,426  
 
                 
 
    253,484       142,447       111,037  
Third parties — refined product pipelines
    38,330       62,720       (24,390 )
 
                 
 
    291,814       205,167       86,647  
 
                       
Terminals and truck loading racks:
                       
Affiliates
    109,539       119,910       (10,371 )
Third parties
    32,737       45,457       (12,720 )
 
                 
 
    142,276       165,367       (23,091 )
 
                 
Total for pipelines and terminal assets (bpd)
    434,090       370,534       63,556  
 
                 

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    Year Ended        
    December 31,     Change from
    2007     2006     2006  
    (In thousands, except per unit data)  
Revenues
                       
Pipelines:
                       
Affiliates — refined product pipelines
  $ 36,281     $ 31,723     $ 4,558  
Affiliates — intermediate pipelines
    13,731       10,733       2,998  
 
                 
 
    50,012       42,456       7,556  
Third parties — refined product pipelines
    36,271       31,685       4,586  
 
                 
 
    86,283       74,141       12,142  
 
                       
Terminals and truck loading racks:
                       
Affiliates
    10,949       10,422       527  
Third parties
    5,427       4,631       796  
 
                 
 
    16,376       15,053       1,323  
Other — affiliates
    2,748             2,748  
 
                 
 
                       
Total revenues
    105,407       89,194       16,213  
 
                       
Operating costs and expenses
                       
Operations
    32,911       28,630       4,281  
Depreciation and amortization
    14,382       15,330       (948 )
General and administrative
    5,043       4,854       189  
 
                 
 
    52,336       48,814       3,522  
 
                 
 
                       
Operating income
    53,071       40,380       12,691  
 
                       
Interest income
    533       899       (366 )
Interest expense, including amortization
    (13,289 )     (13,056 )     (233 )
Gain on sale of assets
    298             298  
Minority interest in Rio Grande Pipeline Company
    (1,067 )     (680 )     (387 )
 
                 
 
    (13,525 )     (12,837 )     (688 )
 
                 
 
                       
Income before income taxes
    39,546       27,543       12,003  
 
                       
State income tax
    (275 )           (275 )
 
                 
 
                       
Net income
    39,271       27,543       11,728  
 
                       
Less general partner interest in net income, including incentive distributions (1)
    2,932       1,710       1,222  
 
                 
 
                       
Limited partners’ interest in net income
  $ 36,339     $ 25,833     $ 10,506  
 
                 
 
                       
Net income per unit applicable to limited partners (1)
  $ 2.26     $ 1.60     $ 0.66  
 
                 
 
                       
Weighted average limited partners’ units outstanding
    16,108       16,108        
 
                 
 
                       
EBITDA(2)
  $ 66,684     $ 55,030     $ 11,654  
 
                 
 
                       
Distributable cash flow (3)
  $ 51,012     $ 47,219     $ 3,793  
 
                 
 
                       
Volumes (bpd)
                       
 
                       
Pipelines:
                       
Affiliates — refined product pipelines
    77,441       69,271       8,170  
Affiliates — intermediate pipelines
    65,006       57,658       7,348  
 
                 
 
    142,447       126,929       15,518  
Third parties — refined product pipelines
    62,720       62,655       65  
 
                 
 
    205,167       189,584       15,583  
 
                       
Terminals and truck loading racks:
                       
Affiliates
    119,910       118,202       1,708  
Third parties
    45,457       43,285       2,172  
 
                 
 
    165,367       161,487       3,880  
 
                 
Total for pipelines and terminal assets (bpd)
    370,534       351,071       19,463  
 
                 
 
(1)   Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes any incentive distributions declared in the period. The net income applicable to the limited partners is divided by the weighted average limited partner units outstanding in computing the net income per unit applicable to limited partners.

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(2)   EBITDA is calculated as net income plus (i) interest expense net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon 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 compliance with financial covenants. See our calculation of EBITDA under Item 6, “Select Financial Data”.
(3)   Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or 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. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. See our calculation of distributable cash flow under Item 6, “Select Financial Data”.
(4)   The amounts reported for the year ended December 31, 2008 include volumes transported on the crude pipelines for the period from March 1, 2008 through December 31, 2008 only. Volumes shipped during the months of March through December 2008 averaged 133.3 thousand barrels per day (“mbpd”). For the year ended December 31, 2008, crude pipeline volumes are based on volumes for the months of March through December, averaged over the 366 days in 2008. Under the Holly CPTA, fees are based on volumes transported on each pipeline component comprising the crude pipeline system (the crude oil gathering pipelines and the crude oil trunk lines). Accordingly, volumes transported on the crude pipelines represent the sum of volumes transported on both pipeline components. In cases where volumes are transported over both components of the crude pipeline system, such volumes are reflected twice in the total crude oil pipeline volumes.
Results of Operations — Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Summary
Net income for the year ended December 31, 2008 was $25.4 million, a $13.9 million decrease compared to the year ended December 31, 2007. This decrease in overall earnings was due principally to the effects of limited production at Alon’s Big Spring Refinery resulting from an explosion and fire in February, a decrease in previously deferred revenue realized and an increase in operating costs and expenses and interest expense. These factors were partially offset by revenues attributable to our crude pipeline assets acquired in the first quarter of 2008, the effect of the annual tariff rate increases and an increase in affiliate refined product shipments. Revenues of $15.7 million relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the year ended December 31, 2008. Such deferred revenue will be recognized in 2009 either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused after a twelve-month period.
On February 18, 2008, Alon experienced an explosion and fire at its Big Spring refinery that resulted in the shutdown of production. In early April, Alon reopened its Big Spring refinery and resumed production at about one-half of refining capacity until production was restored in late September and later increased to full capacity during the fourth quarter. Lost production and reduced operations attributable to this incident resulted in a decrease in third party shipments on our refined product pipelines during the first nine months of 2008. Under our pipelines and terminals agreement with Alon, Alon has committed to a level of product shipments that generally results in a minimum level of annual revenue. If Alon does not

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meet their minimum commitments, we bill them quarterly an amount related to such shortfalls. Although these shortfall billings are required to be recorded as deferred revenues, such shortfall billings are included in our distributable cash flow as they occur.
Revenues
Total revenues for the year ended December 31, 2008 were $118.1 million, a $12.7 million increase compared to the year ended December 31, 2007. This increase was due principally to revenues attributable to our crude pipeline assets acquired in the first quarter of 2008, an increase in affiliate refined product shipments and the effect of annual tariff rate increases. These increases were partially offset by a decrease in third party shipments, a decrease in shipments on our intermediate pipeline system and a net decrease in previously deferred revenue realized. Also affecting our revenue comparison was 2007 third quarter revenue of $2.7 million related to our sale of inventory of accumulated overages of refined products at our terminals. There was no comparable revenue for the year ended December 31, 2008.
Revenues from our refined product pipelines were $69.0 million, a decrease of $3.5 million compared to the year ended December 31, 2007. This decrease was due to a decline in third party shipments as a result of reduced production and downtime following an explosion at Alon’s Big Spring refinery during the first quarter and a $0.5 million decrease in previously deferred revenue realized. These decreases were partially offset by an increase in affiliate shipments and the effect of the annual tariff rate increase on refined product shipments. Overall shipments on our refined product pipeline system decreased to an average of 121.5 mbpd compared to 140.2 mbpd for the same period last year.
Revenues from our intermediate pipelines were $11.9 million, a decrease of $1.8 million compared to the year ended December 31, 2007. This decrease was due to the effects of downtime at Holly’s Navajo Refinery during the second quarter of 2008 and a $1.2 million decrease in previously deferred revenue realized. These decreases were partially offset by the effect of the annual tariff rate increase on intermediate pipeline shipments. Shipments on our intermediate product pipeline system decreased to an average of 58.9 mbpd compared to 65.0 mbpd for the same period last year.
Revenues from our crude pipelines were $22.4 million; shipments for the months of March through December 2008 averaged 133.3 mbpd.
Revenues from terminal, tankage and truck loading rack fees were $14.8 million, a decrease of $1.6 million compared to the year ended December 31, 2007. This decrease is due principally to the effects of downtime at Alon’s Big Spring Refinery during the first nine months of 2008 and downtime at Holly’s Navajo Refinery during the second quarter of 2008. Refined products terminalled in our facilities decreased to an average of 142.3 mbpd compared to 165.4 mbpd for the same period last year.
Other revenues for the year ended December 31, 2007 consisted of $2.7 million related to the sale of inventory of accumulated terminal overages of refined product to Holly. There was no comparable revenue for the year ended December 31, 2008.
Operations Expense
Operations expense for the year ended December 31, 2008 increased by $8.4 million compared to the year ended December 31, 2007. This increase in expense was due principally to the operations of our crude pipelines commencing March 1, 2008 and increased pipeline maintenance and payroll costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2008 increased by $8.5 million compared to the year ended December 31, 2007, due principally to depreciation and amortization attributable to our newly acquired crude pipelines, tankage assets and related transportation agreement.

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General and Administrative
General and administrative costs for the year ended December 31, 2008 increased by $1.3 million compared to the year ended December 31, 2007, due principally to an increase professional fees and equity based compensation expense.
Interest Expense
Interest expense for the year ended December 31, 2008 totaled $21.8 million, an increase of $8.5 million compared to the year ended December 31, 2007. This increase is due principally to interest attributable to advances from our revolving credit agreement that were used to finance the purchase of the Crude Pipelines and Tankage Assets in the first quarter as well as capital projects. Additionally, interest expense for the year ended December 31, 2008 includes $2.3 million in non-cash interest expense as a result of the application of fair value accounting to two of our interest rate swap agreements. For the year ended December 31, 2008, our aggregate effective interest rate was 5.6% compared to 7.2% for 2007.
Minority Interest in Earnings of Rio Grande
The minority interest related to the 30% of Rio Grande that we do not own reduced our income by $1.3 for the year ended December 31, 2008 compared to $1.1 million for the year ended December 31, 2007.
State Income Tax
We recorded state income taxes of $0.3 million for each of the years ended December 31, 2008 and 2007 that are solely attributable to the Texas margin tax.
Results of Operations — Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Summary
Net income for the year ended December 31, 2007 was $39.3 million, an $11.8 million increase compared to the year ended December 31, 2006. The increase in overall earnings was due principally to an increase in volumes transported on our pipeline systems, the effect of the annual tariff rate increases on product shipments, the realization of certain previously deferred revenue and revenue related to the sale of inventory of accumulated terminal overages of refined product to Holly, partially offset by an increase in our operating costs and expenses. Revenues of $3.7 million relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the year ended December 31, 2007. Such deferred revenue was recognized in 2008 either as payment for shipments in excess of guaranteed levels or when shipping rights expired unused after a twelve-month period.
Revenues
Total revenues for the year ended December 31, 2007 were $105.4, a $16.2 million increase compared to the year ended December 31, 2006. This increase was due principally to an increase in volumes transported on our pipeline systems, the effect of annual tariff rate increases, an increase in previously deferred revenue realized and revenue related to the sale of inventory of accumulated terminal overages of refined product to Holly.
The increase in volumes transported on our pipeline systems for the year ended December 31, 2007 compared to 2006 was due principally to significant downtime at all of the refineries served by our product distribution network in the second quarter of 2006. Refiners were generally required to start producing ultra low sulfur diesel fuel (“ULSD”) by June 2006. To meet this requirement, many refiners, including Holly’s Navajo Refinery and Alon’s Big Spring Refinery, required downtime at their refineries so that ULSD-associated projects could be brought on line. Additionally, Holly completed an expansion of the

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Navajo Refinery during this period of downtime, which resulted in increased refinery production and has contributed to increased volume shipments on our pipeline systems.
Revenues from our refined product pipelines were $72.6 million, an increase of $9.2 million compared to the year ended December 31, 2006. This increase in refined product pipeline revenue was due principally to an increase in volumes shipped on our refined product pipelines, the effect of the annual tariff rate increase on refined product shipments and the realization of $3.1 million of previously deferred revenue. Overall shipments on our refined product pipeline system increased to an average of 140.2 mbpd compared to 131.9 mbpd for the year ended December 31, 2006.
Revenues from our intermediate pipelines were $13.7 million, an increase of $3.0 million compared to the year ended December 31, 2006. This increase was due principally to an increase in volumes shipped on our intermediate pipelines, the effect of the annual tariff rate increase on intermediate pipeline shipments and a $1.4 million increase in previously deferred revenue realized. Shipments on our intermediate product pipeline system increased to an average of 65.0 mbpd compared to 57.7 mbpd for the year ended December 31, 2006.
Revenues from terminal and truck loading rack service fees were $16.4 million, an increase of $1.3 million compared to the year ended December 31, 2006. This increase was due principally to an increase in refined products terminalled in our facilities. Refined products terminalled in our facilities increased to an average of 165.4 mbpd compared to 161.5 mbpd for the year ended December 31, 2006.
Other revenues for the year ended December 31, 2007 consisted of $2.7 million related to the sale of inventory of accumulated terminal overages of refined product to Holly. These overages arose from net product gains at our terminals from the beginning of 2005 through the third quarter of 2007. In the fourth quarter of 2007, we amended our pipelines and terminals agreement with Holly to provide that, on a go-forward basis, such terminal overages of refined product belong to Holly. There were no other revenues for the year ended December 31, 2006.
Operations Expense
Operations expense for the year ended December 31, 2007 increased $4.3 million compared to the year ended December 31, 2006. This increase in expense was due principally to higher throughput volumes, an increase in pipeline and terminal maintenance expense and an increase in the cost of employees who perform services for us, including the addition of two new senior level executives.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2007 decreased by $0.9 million compared to the year ended December 31, 2006, due principally to a reduction in amortization expense, as a transportation agreement became fully amortized in April 2007.
General and Administrative
General and administrative costs for the year ended December 31, 2007 increased by $0.2 million compared to the year ended December 31, 2006, due principally to an increase in equity-based incentive compensation expense.
Interest Expense
Interest expense for the year ended December 31, 2007 totaled $13.3 million, an increase of $0.2 million from $13.1 million for the year ended December 31, 2006. For the year ended December 31, 2007, our aggregate effective interest rate was 7.2% compared to 7.1% for 2006.
Minority Interest in Earnings of Rio Grande
The minority interest related to the 30% of Rio Grande that we do not own reduced our income by $1.1 for the year ended December 31, 2007 compared to $0.7 million for the year ended December 31, 2006.

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State Income Tax
Effective January 1, 2007, the Texas margin tax applied to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. As a result, we recorded $0.3 million in state income tax for the year ended December 31, 2007 that is solely attributable to the Texas margin tax. There was no comparable state income tax for the year ended December 31, 2006.
LIQUIDITY AND CAPITAL RESOURCES
Overview
In February 2008, we amended our $100.0 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100.0 million to $300.0 million, which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. As of December 31, 2008, we had $200.0 million outstanding under the Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are either designated for working capital or have been used as interim financing to fund capital expenditures are classified as short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. During the year ended December 31, 2008, we received net advances totaling $29.0 million under the Credit Agreement that were used as interim financing for capital expenditures.
Our senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (the “Senior Notes”). The Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers.
We renewed our “shelf” registration statement in 2008, under which we may offer from time to time up to $1.0 billion of our securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.
We believe our current cash balances, future internally-generated funds and funds available under our Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future. With the current conditions in the credit and equity markets, there may be limits on our ability to issue new debt or equity securities. Additionally, due to pricing in the current debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. As a result, our ability to fund certain of our planned capital expenditures and other business opportunities may be limited.
In February, May, August and November 2008, we paid regular quarterly cash distributions of $0.725, $0.735, $0.745 and $0.755, respectively, on all units, an aggregate amount of $52.4 million. Included in these distributions was an aggregate of $3.1 million paid to the general partner as incentive distributions, as the quarterly distributions per unit exceeded the target distribution amount of $0.55.
Cash and cash equivalents decreased by $5.1 million during the year ended December 31, 2008. The cash flows used for investing activities of $213.3 million, exceeded cash flows provided by operating and financing activities of $63.7 million and $144.6, respectively. Working capital decreased by $43.3 million due principally to $29.0 million in interim financing of capital projects.

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Cash Flows — Operating Activities
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Cash flows from operating activities increased by $4.6 million from $59.1 million for the year ended December 31, 2007 to $63.7 million for the year ended December 31, 2008. This increase is due principally to $20.8 million in additional cash collections from our major customers, resulting principally from increased revenues and shortfall billings, partially offset by miscellaneous year-over-year changes in collections and payments.
Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Certain of these shippers then have the right to recapture these amounts if future volumes exceed minimum levels. For the year ended December 31, 2008, we received cash payments of $14.3 million related to shortfall billings under these commitments. We billed $3.8 million during the year ended December 31, 2007 related to shortfalls that occurred in this period that expired without recapture and was recognized as revenue during the year ended December 31, 2008. Another $1.8 million is included in our accounts receivable at December 31, 2008 related to shortfalls that occurred in the fourth quarter of 2008.
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows from operating activities increased by $13.2 million from $45.9 million for the year ended December 31, 2006 to $59.1 million for the year ended December 31, 2007. This increase is due principally to $14.8 million in additional cash collections from our major customers, resulting principally from increased revenues and shortfall billings, partially offset by miscellaneous year-over-year changes in collections and payments.
For the year ended December 31, 2007, we received cash payments of $4.6 million related to shortfall billings. We billed $5.5 million during the year ended December 31, 2006 related to shortfalls that occurred in this period that expired without recapture and was recognized as revenue in the year ended December 31, 2007. Another $0.4 million is included in our accounts receivable at December 31, 2007 related to shortfalls that occurred in the fourth quarter of 2007.
Cash Flows — Investing Activities
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Cash flows used for investing activities increased by $203.7 million from $9.6 million for the year ended December 31, 2007 to $213.3 million for the year ended December 31, 2008. In connection with our purchase of the Crude Pipelines and Tankage Assets on February 29, 2008, we paid cash consideration to Holly of $171.0 million. Additions to properties and equipment for the year ended December 31, 2008 was $42.3 million, an increase of $32.3 million from $10.0 million for the year ended December 31, 2007.
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows used for investing activities increased by $0.5 million from $9.1 million for the year ended December 31, 2006 to $9.6 million for the year ended December 31, 2007. Additions to properties and equipment for the year ended December 31, 2007 was $10.0 million, an increase of $0.9 million from $9.1 million for the year ended December 31, 2006. During the year ended December 31, 2007, we also received cash proceeds of $0.3 million related to the sale of certain assets.
Cash Flows — Financing Activities
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Cash flows provided by financing activities increased by $195.3 million from $50.7 million used for financing activities for the year ended December 31, 2007 to $144.6 million provided by financing activities for the ended December 31, 2008. During the year ended December 31, 2008, we received net advances of $200.0 million under the Credit Agreement of which $171.0 million was used to finance the cash portion of the consideration paid to acquire the Crude Pipelines and Tankage Assets on February 29, 2008. During the year ended December 31, 2008, we paid cash distributions on all units and the

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general partner interest in the aggregate amount of $52.4 million, an increase of $4.4 million from $48.0 million for the year ended December 31, 2007. Cash distributions paid to the minority interest owner in Rio Grande was $1.8 million for the year ended December 31, 2008, an increase of $0.6 million from $1.3 million for the year ended December 31, 2007. Cash paid for the purchase of our common units for restricted grants was $0.8 million for the year ended December 31, 2008, a decrease of $0.3 million from $1.1 million for the year ended December 31, 2007. Also for the year ended December 31, 2008, we paid $0.7 million in deferred financing costs that were attributable to the amendment to our Credit Agreement.
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows used for financing activities increased by $4.9 million from $45.8 million for the year ended December 31, 2006 to $50.7 million for the ended December 31, 2007. During the year ended December 31, 2007, we paid cash distributions on all units and the general partner interest in the aggregate amount of $48.0 million, an increase of $4.3 million from $43.7 million for the year ended December 31, 2006. Cash distributions paid to the minority interest owner in Rio Grande was $1.3 million for the year ended December 31, 2007, a decrease of $0.2 million from $1.5 million for the year ended December 31, 2006. Cash paid for the purchase of our common units for restricted grants was $1.1 million for the year ended December 31, 2007, an increase of $0.5 million from $0.6 million for the year ended December 31, 2006. Also for the year ended December 31, 2007, we paid $0.3 million in deferred financing costs that were attributable to the amendment to our Credit Agreement.
Capital Requirements
Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.
Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated to a particular capital project may be expended over a period in excess of a year, 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. The 2009 capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of the South System and the joint venture with Plains All American Pipeline, L.P. discussed below.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. 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 our 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. We expect to complete the majority of this project in early 2009.
In November 2007, we 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 us. We expect to purchase our 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 Holly’s 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 our investment in the SLC Pipeline is expected to be $28.0 million,

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including a $2.5 million finder’s fee that is payable to Holly upon the closing of our investment in the SLC Pipeline.
On January 31, 2008, we entered into an option agreement with Holly, granting us an option to purchase all of Holly’s equity interests in a joint venture pipeline currently under construction. The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. Holly owns 75% of the equity interests in the UNEV Pipeline. Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. 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. Holly’s share of this cost is $225.0 million. On July 17, 2008, Holly announced the purchase of Musket Corporation’s Cedar City, Utah terminal and rail facilities that will serve as part of the UNEV Pipeline’s Cedar City Terminal. Holly’s UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, Holly is currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.
Holly is currently working on a project to deliver additional crude oils to its Navajo Refinery, including a 70-mile pipeline from Centurion Pipeline L.P.’s Slaughter Station in west Texas to Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. Under provisions of the Omnibus Agreement with Holly we will have an option to purchase Holly’s investment in the project at a purchase price to be negotiated with Holly. The projects will increase the pipeline capacity between Lovington and Artesia by 40,000 bpd. The cost of the projects is expected to be $90.0 million and construction is currently expected to be completed and the projects to become fully operational in the fourth quarter of 2009.
We are currently working on a capital improvement project that will provide increased flexibility and capacity to our Intermediate Pipelines enabling us to accommodate increased volumes following Holly’s Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $5.1 million.
Also, we are currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline at an estimated cost of $1.9 million scheduled for completion in early 2009.
We expect that our currently planned expenditures for maintenance capital as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline, SLC Pipeline, South System expansion and Holly crude oil projects described above will be funded with existing cash balances, cash generated by operations, the sale of additional limited partner units, the issuance of debt securities and advances under our $300.0 million senior secured revolving credit agreement maturing August 2011, or a combination thereof. With the current conditions in the credit and equity markets there may be limits on our ability to issue new debt or equity securities. Additionally, due to pricing in the current debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline and Holly’s crude oil project. We are not obligated to purchase these assets nor are we subject to any fees or penalties if HEP’s board of directors decide not to proceed with either of these opportunities.
Credit Agreement
In February 2008, we amended our $100.0 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100.0 million to $300.0 million, which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. As of December 31, 2008 and December 31, 2007, we had $200.0 million and zero, respectively, outstanding under the Credit Agreement.
The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are either designated for

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working capital or have been used as interim financing to fund capital expenditures are classified as short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit. During the year ended December 31, 2008, we received net advances totaling $29.0 million under the Credit Agreement that were used as interim financing for capital expenditures.
We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of December 31, 2008, we did not have any working capital borrowings.
Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of their assets, which other than their investment in HEP, are not significant.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At December 31, 2008, we are subject to a 0.30% commitment fee on the $100.0 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.
The Credit Agreement imposes certain requirements on us, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.
Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.
Senior Notes Due 2015
Our Senior Notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25%. The Senior Notes are unsecured and impose certain restrictive covenants which we are subject to and currently in compliance with, including limitations on our 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 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 Senior Notes.
Indebtedness under the Senior Notes is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of their assets, which other than their investment in HEP, are not significant.

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The carrying amounts of our long-term debt are as follows:
                 
    December 31,  
    2008     2007  
    (In thousands)  
Credit Agreement
  $ 200,000     $  
 
               
Senior Notes
               
Principal
    185,000       185,000  
Unamortized discount
    (2,344 )     (2,724 )
Fair value hedge — interest rate swap
          (841 )
Unamortized premium — dedesignated fair value hedge
    2,137        
 
           
 
    184,793       181,435  
 
           
Total debt
    384,793       181,435  
Less short-term borrowings under credit agreement
    29,000        
 
           
Total long-term debt
  $ 355,793     $ 181,435  
 
           
Our interest rate swap contracts are discussed under “Risk Management.”
The following table presents our long-term contractual obligations as of December 31, 2008.
  Our long-term debt consists of the $185.0 million principal balance of our Senior Notes and $171.0 millon of outstanding principal under our Credit Agreement that we have classified as long-term debt.
 
  The pipeline operating lease amounts below reflect the exercise of the first of three 10-year extensions, expiring in 2017, on our lease agreement for the refined products pipeline between White Lakes Junction and Kuntz Station in New Mexico. However, these amounts exclude the second and third 10-year lease extensions, which based on the current outlook, are likely to be exercised.
 
  Most of our right of way agreements are renewable on an annual basis, and the right of way lease payments below include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2008. For the foreseeable future, we intend to continue renewing these agreements and expect to incur right of way expenses in addition to the payments listed below.
 
  In consideration for Holly’s assistance in obtaining our joint venture opportunity in the SLC Pipeline discussed under “Capital Requirements”, we will pay Holly a $2.5 million finder’s fee upon the closing of our investment in the joint venture with Plains.
                                         
            Payments Due by Period  
            Less than                     Over 5  
    Total     1 Year     2-3 Years     4-5 Years     Years  
    (In thousands)  
Long-term debt — principal
  $ 356,000     $     $     $ 171,000     $ 185,000  
Long-term debt — interest
    75,157       11,563       23,125       23,125       17,344  
Pipeline operating lease
    52,343       6,158       12,316       12,316       21,553  
Right of way leases
    2,130       206       393       329       1,202  
Other
    23,049       5,221       5,178       4,600       8,050  
 
                             
Total
  $ 508,679     $ 23,148     $ 41,012     $ 211,370     $ 233,149  
 
                             
Impact of Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2008, 2007 and 2006.
A substantial majority of our revenues are generated under long-term contracts that include the right to increase our rates and minimum revenue guarantees annually for increases in the PPI. Historically, the PPI has increased an average of 4.3% annually over the past 5 calendar years. With respect to our 15-

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year transportation agreement with Alon, recent data indicates that the annual PPI adjustment may result in a minor tariff rate decrease.
Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. For additional discussion on environmental matter, please see “Environmental Regulation and Remediation” under Item 1, “Business”.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.
Revenue Recognition
Revenues are recognized as products are shipped through our pipelines and terminals. Additional pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in the capacity of one of our pipelines.
Billings to customers for obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:
  the customer receives the future services provided by these billings,
 
  the period in which the customer is contractually allowed to receive the services expires, or
 
  we determine a high likelihood that we will not be required to provide services within the allowed period.
We will recognize shortfall billings as revenue prior to the expiration of the contractual term period to provide services only when we determine with a high likelihood that we will not be required to provide services within the allowed period. We determine this when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period or the customer acknowledges that its anticipated shipment levels will not permit it to utilize such a shortfall credit within the respective contractual make-up period. To date, we have not recognized any shortfall billings as revenue prior to the expiration of the contractual term period.
Long-Lived Assets
We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results,

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and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2008, 2007 and 2006.
Contingencies
It is common in our industry to be 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 types of matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these types of contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.
Recent Accounting Pronouncements
Statement of Financial Accounting Standard (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin (“ARB”) No. 51”
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We will adopt this standard effective January 1, 2009. Upon adoption of this standard, our minority interest balance will be reclassified as a component of “Partners’ equity” in our consolidated balance sheets. At December 31, 2008, our minority interest balance was $10.2 million.
SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
EITF No. 07-04 “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”
In March 2008, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 07-04, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“MLP’s”). This standard provides guidance in the application of the two-class method in computing earnings per unit to reflect an MLP’s contractual obligation to make distributions to the general partner, limited partners, and incentive distribution rights holder. EITF No. 07-04 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
FASB Staff Position (“FSP”) No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities”
In June 2006, the FASB issued FSP No. 03-6-1, Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities. This standard provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under FASB No. 128, Earnings per Share. FSP No. 03-6-1 is effective for fiscal years

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beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
RISK MANAGEMENT
As of December 31, 2008, we have three interest rate swap contracts.
We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2008. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, we measure 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 our swap against the expected future interest payments on our $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008, we had no ineffectiveness on our cash flow hedge.
We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36% as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.
In October 2008, we entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of our hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.
Our interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in our consolidated balance sheets with a corresponding entry to interest expense. For the year ended December 31, 2008, we recognized $2.3 million in interest expense attributable to fair value adjustments to our interest rate swaps.
Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the 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 Senior Notes, effectively adjusting the carrying value this $60.0 million to its fair value. We dedesignated this hedge in October 2008. At this time, the carrying balance of our 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.

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We record 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 our interest rate swaps is as follows:
                         
    Balance Sheet           Location of      
Interest Rate Swaps   Location   Fair Value     Offsetting Balance   Offsetting Amount  
                (In thousands)        
Asset
                       
Fixed-to-variable interest rate swap — $60 million of 6.25% Senior Notes
  Other assets   $ 4,079     Long-term debt
  $ (2,195
)
        Interest expense   $ (1,884 )
 
                   
 
      $ 4,079         $ (4,079 )
 
                   
 
                       
Liability
                       
Cash flow hedge — $171 million LIBOR based debt
  Other long-term liabilities   $ (12,967 )   Accumulated other comprehensive income   $ 12,967  
Variable-to-fixed interest rate swap — $60 million
  Other long-term liabilities     (4,166 )   Interest expense     4,166  
 
                   
 
      $ (17,133 )       $ 17,133  
 
                   
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.
At December 31, 2008, we had an outstanding principal balance on our 6.25% Senior Notes of $185.0 million. By means of our interest rate swap contracts, we have effectively converted the 6.25% fixed rate on $60.0 million of the Senior Notes to a fixed rate of 4.75%. A change in interest rates would generally affect the fair value of the debt, but not our earnings or cash flows. At December 31, 2008, the fair value of our Senior Notes was $124.0 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the Senior Notes at December 31, 2008 would result in a change of approximately $7.8 million in the fair value of the debt.
At December 31, 2008, our cash and cash equivalents included highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a 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 market interest rates on our 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 monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”
Since we do not own products shipped on our pipelines or terminalled at our terminal facilities we do not have market risks associated with commodity prices.

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Item 8. Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE COMPANY’S INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Energy Partners, L.P. (the “Partnership”) 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 Partnership’s internal control over financial reporting as of December 31, 2008 using the criteria for effective control over financial reporting established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that, as of December 31, 2008, the Partnership maintained effective internal control over financial reporting.
The Partnership’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008. That report appears on page 62.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Holly Logistic Services, L.L.C. and
Unitholders of Holly Energy Partners, L.P.
We have audited Holly Energy Partners, L.P.’s (the “Partnership”) internal control over financial reporting as of December 31 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The Partnership’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 partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Holly Energy Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Holly Energy Partners, L.P. as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2008, our report dated February 13, 2009, expressed an unqualified opinion thereon.
         
     
  /s/ ERNST & YOUNG LLP    
     
Dallas, Texas
February 13, 2009

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Holly Logistic Services, L.L.C. and
Unitholders of Holly Energy Partners, L.P.
We have audited the accompanying consolidated balance sheets of Holly Energy Partners, L.P. (the “Partnership”) as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Partnership’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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Energy Partners, L.P. at December 31, 2008 and 2007, and the related consolidated results of its operations and its cash flows, for each of the three years in the period ended December 31, 2008 in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 13, 2009 expressed an unqualified opinion thereon.
         
     
  /s/ ERNST & YOUNG LLP    
     
Dallas, Texas
February 13, 2009

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Holly Energy Partners, L.P.
Consolidated Balance Sheets
                 
    December 31,  
    2008     2007  
    (In thousands, except unit data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 5,269     $ 10,321  
Accounts receivable:
               
Trade
    5,082       6,611  
Affiliates
    9,395       5,700  
 
           
 
    14,477       12,311  
 
               
Prepaid and other current assets
    593       546  
 
           
Total current assets
    20,339       23,178  
 
               
Properties and equipment, net
    290,284       158,600  
Transportation agreements, net
    122,383       54,273  
Other assets
    6,682       2,853  
 
           
 
               
Total assets
  $ 439,688     $ 238,904  
 
           
 
               
LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)
               
Current liabilities:
               
Accounts payable
  $ 5,816     $ 3,011  
Accounts payable — affiliates
    2,202       6,021  
Accrued interest
    2,845       2,996  
Deferred revenue
    15,658       3,700  
Accrued property taxes
    1,145       1,177  
Other current liabilities
    1,505       827  
Short-term borrowings under credit agreement
    29,000        
 
           
Total current liabilities
    58,171       17,732  
 
               
Commitments and contingencies
           
Long-term debt
    355,793       181,435  
Other long-term liabilities
    17,604       1,181  
Minority interest
    10,218       10,740  
 
               
Partners’ equity (deficit):
               
Common unitholders (8,390,000 and 8,170,000 units issued and outstanding at December 31, 2008 and 2007, respectively)
    169,126       172,807  
Subordinated unitholders (7,000,000 units issued and outstanding at December 31, 2008 and 2007)
    (85,059 )     (73,725 )
Class B subordinated unitholders (937,500 units issued and outstanding at December 31, 2008 and 2007)
    21,455       22,973  
General partner interest (2% interest)
    (94,653 )     (94,239 )
Accumulated other comprehensive loss
    (12,967 )      
 
           
 
               
Total partners’ equity (deficit)
    (2,098 )     27,816  
 
           
 
               
Total liabilities and partners’ equity (deficit)
  $ 439,688     $ 238,904  
 
           
See accompanying notes.

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Holly Energy Partners, L.P.
Consolidated Statements of Income
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands, except per unit data)  
Revenues:
                       
Affiliates
  $ 85,040     $ 63,709     $ 52,878  
Third parties
    33,048       41,698       36,316  
 
                 
 
    118,088       105,407       89,194  
 
                 
 
                       
Operating costs and expenses:
                       
Operations
    41,270       32,911       28,630  
Depreciation and amortization
    22,889       14,382       15,330  
General and administrative
    6,377       5,043       4,854  
 
                 
 
    70,536       52,336       48,814  
 
                 
 
                       
Operating income
    47,552       53,071       40,380  
 
                       
Other income (expense):
                       
Interest income
    159       533       899  
Interest expense
    (21,763 )     (13,289 )     (13,056 )
Gain on sale of assets
    36       298        
Other Income
    996              
Minority interest in Rio Grande Pipeline Company
    (1,278 )     (1,067 )     (680 )
 
                 
 
    (21,850 )     (13,525 )     (12,837 )
 
                 
 
                       
Income before income taxes
    25,702       39,546       27,543  
 
                       
State income tax
    (335 )     (275 )      
 
                 
 
                       
Net income
    25,367       39,271       27,543  
 
                       
Less general partner interest in net income
    3,543       2,932       1,710  
 
                 
 
                       
Limited partners’ interest in net income
  $ 21,824     $ 36,339     $ 25,833  
 
                 
 
                       
Net income per limited partners’ unit — basic and diluted
  $ 1.34     $ 2.26     $ 1.60  
 
                 
 
                       
Weighted average limited partners’ units outstanding
    16,291       16,108       16,108  
 
                 
See accompanying notes.

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Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
Cash flows from operating activities
                       
Net income
  $ 25,367     $ 39,271     $ 27,543  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    22,889       14,382       15,330  
Change in fair value — interest rate swaps
    2,282              
Minority interest in Rio Grande Pipeline Company
    1,278       1,067       680  
Amortization of restricted and performance units
    1,688       1,375       927  
Gain on sale of assets
    (36 )     (298 )      
(Increase) decrease in current assets:
                       
Accounts receivable
    1,529       728       (4,263 )
Accounts receivable — affiliates
    (3,695 )     16       (637 )
Prepaid and other current assets
    (47 )     666       115  
Increase (decrease) in current liabilities:
                       
Accounts payable
    2,805       (770 )     761  
Accounts payable — affiliates
    (3,819 )     3,823       764  
Accrued interest
    (151 )     55       49  
Deferred revenue
    11,958       (1,786 )     4,473  
Accrued property taxes
    (32 )     309       (144 )
Other current liabilities
    678       (271 )     (215 )
Other, net
    957       489       470  
 
                 
Net cash provided by operating activities
    63,651       59,056       45,853  
 
                 
 
                       
Cash flows from investing activities
                       
Additions to properties and equipment
    (42,303 )     (9,957 )     (9,107 )
Acquisition of crude pipelines and tankage assets
    (171,000 )            
Proceeds from sale of assets
    36       325        
 
                 
Net cash used for investing activities
    (213,267 )     (9,632 )     (9,107 )
 
                 
 
                       
Cash flows from financing activities
                       
Net borrowings under credit agreement
    200,000              
Proceeds from issuance of common units
    104              
Contribution from general partner
    186              
Distributions to partners
    (52,426 )     (47,974 )     (43,670 )
Distributions to minority interest
    (1,800 )     (1,290 )     (1,470 )
Purchase of units for restricted grants
    (795 )     (1,082 )     (634 )
Deferred financing costs
    (705 )     (296 )      
Other
          (16 )      
 
                 
Net cash provided by (used for) financing activities
    144,564       (50,658 )     (45,774 )
 
                 
 
                       
Cash and cash equivalents
                       
Decrease for the year
    (5,052 )     (1,234 )     (9,028 )
Beginning of year
    10,321       11,555       20,583  
 
                 
 
End of year
  $ 5,269     $ 10,321     $ 11,555  
 
                 
See accompanying notes.

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Holly Energy Partners, L.P.
Consolidated Statements of Partners’ Equity (Deficit)
                                                 
                                    Accumulated        
                    Class B     General     Other        
    Common     Subordinated     Subordinated     Partner     Comprehensive        
    Units     Units     Units     Interest     Loss     Total  
    (In thousands)  
 
Balance December 31, 2005
  $ 184,568     $ (63,153 )   $ 24,388     $ (93,743 )   $     $ 52,060  
 
Distributions to partners
    (21,120 )     (18,095 )     (2,423 )     (2,032 )           (43,670 )
Purchase of units for restricted grants
    (634 )                             (634 )
Amortization of restricted units
    927                               927  
Net income
    13,103       11,226       1,504       1,710             27,543  
 
                                   
 
                                               
Balance December 31, 2006
    176,844       (70,022 )     23,469       (94,065 )           36,226  
 
                                               
Distributions to partners
    (22,762 )     (19,495 )     (2,611 )     (3,106 )           (47,974 )
Purchase of units for restricted grants
    (1,082 )                             (1,082 )
Amortization of restricted and performance units
    1,375                               1,375  
Net income
    18,432       15,792       2,115       2,932             39,271  
 
                                   
 
                                               
Balance December 31, 2007
    172,807       (73,725 )     22,973       (94,239 )           27,816  
 
                                               
Distributions to partners
    (24,788 )     (20,720 )     (2,775 )     (4,143 )           (52,426 )
Purchase of units for restricted grants
    (795 )                             (795 )
Amortization of restricted and performance units
    1,688                               1,688  
Issuance of common units
    9,104                               9,104  
Cost of issuing common units
    (71 )                             (71 )
Capital contribution
                      186             186  
Comprehensive income:
                                               
Net income
    11,181       9,386       1,257       3,543             25,367  
Change in fair value — cash flow hedge
                            (12,967 )     (12,967 )
 
                                   
Comprehensive income
    11,181       9,386       1,257       3,543       (12,967 )     12,400  
 
                                   
 
                                               
Balance December 31, 2008
  $ 169,126     $ (85,059 )   $ 21,455     $ (94,653 )   $ (12,967 )   $ (2,098 )
 
                                   
See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2008
Note 1: Description of Business and Summary of Significant Accounting Policies
Description of Business
Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 46% owned by Holly Corporation (“Holly”). We commenced operations on July 13, 2004 upon the completion of our initial public offering. In these consolidated financial statements, the words “we”, “our”, “ours” and “us” refer to HEP unless the context otherwise indicates.
We operate in one business segment — the operation of petroleum product and crude oil pipelines, tankage and terminal facilities.
One of Holly’s wholly-owned subsidiaries owns a refinery in Artesia, New Mexico, which Holly operates in conjunction with crude, vacuum distillation and other facilities situated in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery produces high-value refined products such as gasoline, diesel fuel and jet fuel and serves markets in the southwestern United States and northern Mexico. We own and operate the two parallel intermediate feedstock pipelines (the “Intermediate Pipelines”), which connect the New Mexico refining facilities. Our operations serving the Navajo Refinery include refined product pipelines that serve as part of the refinery’s product distribution network. We also own and operate crude oil pipelines and on-site crude oil tankage that supply and support the refinery. Our terminal operations serving the Holly’s Navajo Refinery include a truck rack at the Navajo Refinery and five integrated refined product terminals located in New Mexico, Texas and Arizona.
Another of Holly’s wholly-owned subsidiaries owns a refinery located near Salt Lake City, Utah (the “Woods Cross Refinery”). Our operations serving the Woods Cross Refinery include crude oil and refined product pipelines, crude oil tankage and a truck rack at the refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho.
See Note 2 for information on the crude pipelines and tankage assets acquired from Holly on February 29, 2008 (the “Crude Pipelines and Tankage Assets”).
We also own and operate refined products pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas.
Additionally, we own a refined product terminal in Mountain Home, Idaho, and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which provides transportation of liquid petroleum gases to northern Mexico.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our subsidiaries and Rio Grande. All significant inter-company transactions and balances have been eliminated. The pipeline and terminal assets that were contributed to us from Holly concurrently with the completion of our initial public offering in 2004, as well as the intermediate pipeline assets that were purchased from Holly in July 2005 were accounted for as transactions among entities under common control. Accordingly, these assets were recorded on our balance sheets at Holly’s book basis instead of our purchase price or fair value.
If the assets transferred to us upon our initial public offering in 2004 and the intermediate pipelines purchased from Holly in 2005 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $157.3 million would have been recorded as increases to our properties and equipment and intangible assets instead of reductions to our partners’ equity.

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Use of Estimates
The preparation of financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid investments with maturity of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheet approximate fair value due to the short-term maturity of these instruments.
Accounts Receivable
The majority of the accounts receivable are due from affiliates of Holly, Alon or independent 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, may be required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal.
Inventories
Inventories consisting of materials and supplies used for operations are stated at the lower of cost, using the average cost method, or market and are shown under “Prepaid and other current assets” in our consolidated balance sheets.
Properties and Equipment
Properties and equipment are stated at cost. Depreciation is provided by the straight-line method over the estimated useful lives of the assets; primarily 10 to 16 years for terminal facilities, 23 to 33 years for pipelines and 3 to 10 years for corporate and other assets. Maintenance, repairs and major replacements are generally expensed as incurred. Costs of replacements constituting improvement are capitalized.
Transportation Agreements
The transportation agreement assets are stated at cost and are being amortized over the periods of the agreements using the straight-line method.
Long-Lived Assets
We evaluate long-lived assets, including intangible 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 periods included in these financial statements.
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 our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.
We have asset retirement obligations with respect to certain of our assets due to legal obligations to clean and/or dispose of various component parts at the time they are retired. At December 31, 2008, an asset retirement obligation of $0.4 million is included in “Other long-term liabilities” in our consolidated balance sheets.

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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 interest rate swaps that we measure at fair value on a recurring basis using level 2 inputs. Our 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. Our measurements are computed using the forward LIBOR yield curve, a market-based observable input, at our respective measurement dates. See Note 6 for additional information on our interest rate swaps.
Revenue Recognition
Revenues are recognized as products are shipped through our pipelines and terminals. Billings to customers for obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:
  the customer receives the future services provided by these billings,
 
  the period in which the customer is contractually allowed to receive the services expires, or
 
  we determine a high likelihood that we will not be required to provide services within the allowed period.
We recognize shortfall billings as revenue prior to the expiration of the contractual term period to provide services only when we determine with a high likelihood that we will not be required to provide services within the allowed period. We determine this when based on current and projected shipping levels, that our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make up period or the customer acknowledges that its anticipated shipment levels will not permit it to utilize such a shortfall credit within the respective contractual make up period. To date, we have not recognized any shortfall billings as revenue prior to the expiration of the contractual term period.
Additional pipeline transportation revenues result from an operating lease to a third party of an interest in the capacity of one of our pipelines.
Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.
Environmental Costs
Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Environmental costs recoverable through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable. At December 31, 2008, we had an accrual of $0.2 million related to environmental remediation obligations.

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State Income Tax
Effective January 1, 2007, the Texas margin tax applied to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.
We are organized as a pass-through for federal income tax purposes. As a result, our partners are responsible for federal income taxes based on their respective share of taxable income.
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us.
Net Income per Limited Partners’ Unit
We have identified the general partner interest and the subordinated units as participating securities and use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the year. Net income per unit applicable to limited partners (including subordinated units and Class B subordinated units) is computed by dividing limited partners’ interest in net income, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of outstanding common and subordinated units.
Recent Accounting Pronouncements
SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin (“ARB”) No. 51”
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We will adopt this standard effective January 1, 2009. Upon adoption of this standard, our minority interest balance will be reclassified as a component of “Partners’ equity” in our consolidated balance sheets. At December 31, 2008, our minority interest balance was $10.2 million.
SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008 and interim periods with in those fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.

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EITF No. 07-04 “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”
In March 2008, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 07-04, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“MLP’s”). This standard provides guidance in the application of the two-class method in computing earnings per unit to reflect an MLP’s contractual obligation to make distributions to the general partner, limited partners, and incentive distribution rights holder. EITF No. 07-04 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
FASB Staff Position (“FSP”) No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities”
In June 2006, the FASB issued FSP No. 03-6-1, Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities. This standard provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under SFAS No. 128, Earnings per Share. FSP No. 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
Note 2: Holly Crude Pipelines and Tankage Transaction
On February 29, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly for $180.0 million that consist of crude oil trunk lines that deliver crude oil to Holly’s 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, a leased jet fuel terminal in Roswell, New Mexico and crude oil and product pipelines that support Holly’s Woods Cross Refinery. The consideration paid consisted of $171.0 million in cash and 217,497 of our common units having a fair value of $9.0 million. We financed the $171.0 million cash portion of the consideration through borrowings under our senior secured revolving credit agreement expiring August 2011.
In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with Holly. Under the Holly CPTA, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities that at the agreed rates will result in minimum annual payments to us of $26.8 million. These minimum annual payments or revenue will be 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 will generally be increased annually by the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC index is the change in the PPI plus a FERC adjustment factor which is reviewed periodically. Additionally, Holly amended our omnibus agreement (the “Omnibus Agreement”) to provide $7.5 million of indemnification for a period of up to fifteen years for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our acquisition.
The $180.0 million purchase price and $0.3 million of related transaction costs was allocated to the underlying Crude Pipelines and Tankage Assets based on values derived under both market and cost valuation approaches. Under the market approach, certain values were obtained based on an analysis of sales data for similar assets in the market, adjusted for certain factors. Under the cost approach, the replacement cost of certain assets, adjusted for factors including age and physical wear, served as the basis for value. As a result, we recorded property and equipment of $106.1 million. Additionally we recorded an intangible asset of $74.2 million representing the value of the Holly CPTA. This value was derived under an income approach based on the agreement’s expected contribution to our future earnings. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

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Note 3: Properties and Equipment
                 
    December 31,  
    2008     2007  
    (In thousands)  
 
               
Pipelines and terminals
  $ 308,056     $ 196,800  
Land and right of way
    24,991       22,825  
Other
    11,498       5,706  
Construction in progress
    38,589       9,103  
 
           
 
    383,134       234,434  
Less accumulated depreciation
    92,850       75,834  
 
           
 
  $ 290,284     $ 158,600  
 
           
During the year ended December 31, 2008 we capitalized $1.0 million in interest related to major construction projects. We did not capitalize any interest prior to 2008.
Depreciation expense was $16.7 million, $11.8 million and $11.2 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Note 4: Transportation Agreements
Our transportation agreements consist of the following:
  The Alon transportation agreement represents a portion of the total purchase price of the Alon assets that was allocated based on an estimated fair value derived under an income approach. This asset is being amortized over 30 years ending 2035, the 15-year initial term of the Alon PTA plus the expected 15-year extension period.
 
  The Holly crude pipelines and tankage agreement represents a portion of the total purchase price of the Crude Pipelines and Tankage Assets that was allocated using a fair value based on the agreement’s expected contribution to our future earnings under an income approach. This asset is being amortized over 15 years ending 2023, the 15-year term of the Holly CPTA.
The carrying amounts of the transportation agreements are as follows:
                 
    December 31,  
    2008     2007  
    (In thousands)  
 
               
Alon transportation agreement
  $ 59,933     $ 59,933  
Holly crude pipelines and tankage agreement
    74,231        
 
           
 
    134,164       59,933  
Less accumulated amortization
    11,781       5,660  
 
           
 
  $ 122,383     $ 54,273  
 
           
We have two additional 15-year transportation agreements with Holly. One of the agreements relates to the pipelines and terminals contributed to us from Holly at the time of our initial public offering in 2004 (the “Holly PTA”). The second agreement relates to the Intermediate Pipelines acquired from Holly in 2005 (the “Holly IPA”). Our basis in the assets acquired under these transfers reflect Holly’s historical cost and do not reflect a step-up in basis to fair value. Therefore, these agreements have a recorded value of zero.

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Note 5: Employees, Retirement and Benefit Plans
Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C. (“HLS”), a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs are charged to us monthly in accordance with the Omnibus Agreement.
These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs for the years ended December 31, 2008, 2007 and 2006 was $2.1 million, $1.3 million and $1.4 million, respectively. These amounts include retirement costs of $1.1 million, $0.6 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.
We have adopted an incentive plan (“Long-Term Incentive Plan”) for employees, consultants and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted units, performance units, unit options and unit appreciation rights.
On December 31, 2008, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $1.9 million, $1.3 million and $0.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. It is currently our policy to purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At December 31, 2008, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 226,268 had not yet been granted.
Restricted Units
Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The vesting for certain key executives is contingent upon certain earnings per unit targets being realized. The fair value of each unit of restricted unit awards was measured at the market price as of the date of grant and is being amortized over the vesting period, including the units issued to the key executives, as we expect those units to fully vest.
A summary of restricted unit activity and changes during the year ended December 31, 2008 is presented below:
                                 
                    Weighted-        
            Weighted-     Average     Aggregate  
            Average     Remaining     Intrinsic  
            Grant-Date     Contractual     Value  
Restricted Units   Grants     Fair Value     Term     ($000)  
 
Outstanding at January 1, 2008 (not vested)
    44,711     $ 44.77                  
Granted
    27,088       38.43                  
Forfeited
    (740 )     49.74                  
Vesting and transfer of full ownership to recipients
    (17,554 )     45.42                  
 
                             
Outstanding at December 31, 2008 (not vested)
    53,505     $ 41.28     1.2 years   $ 1,142  
 
                       
There were 17,554 restricted units having a fair value of $0.4 million that were vested and transferred to recipients of our restricted unit grants during the year ended December 31, 2008. The total intrinsic value of restricted units that were vested and transferred during the year ended December 31, 2007 was $0.6 million. There were no restricted units vested or transferred prior to 2007. As of December 31, 2008, there was $0.6 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 1.2 years.
In 2008, we paid $0.8 million for the purchase of 21,459 of our common units in the open market for the recipients of all 2008 restricted unit grants.

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Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives and employees who perform services for us. These performance units are payable upon meeting the performance criteria over a service period, and generally vest over a period of three years. Our initial performance grant of 1,514 units in 2005 vested in the first quarter of 2008. Payment was based upon our unit price and upon our total unitholder return during the requisite period as compared to the total unitholder return of a selected peer group of partnerships. The amount payable under all other performance unit grants is based upon the growth in distributions per limited partner unit during the requisite period. As of December 31, 2008, estimated share payouts for outstanding nonvested performance unit awards ranged from 125% to 150%.
We granted 14,337 performance units to certain officers in March 2008. These units will vest over a three-year performance period ending December 31, 2010 and are payable in HEP common units. The number of units actually earned will be based on the growth of distributions to limited partners over the performance period, and can range from 50% to 150% of the number of performance units issued. The fair value of these performance units is based on the grant date closing unit price of $40.54 and will apply to the number of units ultimately awarded.
A summary of performance unit activity and changes during the year ended December 31, 2008 is presented below:
         
    Payable
Performance Units   In Units
 
       
Outstanding at January 1, 2008 (not vested)
    24,148  
Vesting and payment of units to recipients
    (1,514 )
Granted
    14,337  
Forfeited
     
 
       
Outstanding at December 31, 2008 (not vested)
    36,971  
 
       
There were 1,514 performance units having a fair value of $0.1 million that were vested and transferred to recipients during the year ended December 31, 2008. There were no payments or units issued for performance units vesting during the years ended December 31, 2007 and 2006. Based on the weighted average fair value at December 31, 2008 of $42.10, there was $0.8 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.5 years.
Note 6: Debt
Credit Agreement
In February 2008, we amended our $100.0 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100.0 million to $300.0 million (the “Credit Agreement”), which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. As of December 31, 2008, we had $200.0 million outstanding under the Credit Agreement.
The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are either designated for working capital or have been used as interim financing to fund capital expenditures are classified as short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit. During the year ended December 31, 2008, we received net advances totaling $29.0 million under the Credit Agreement that were used as interim financing for capital expenditures.

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Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of their assets, which other than their investment in HEP, are not significant.
We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of December 31, 2008, we did not have any working capital borrowings.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At December 31, 2008, we are subject to a 0.30% commitment fee on the $100.0 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.
The Credit Agreement imposes certain requirements on us, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.
Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.
Senior Notes Due 2015
Our Senior Notes maturing March 1, 2015 are registered with the U.S. Securities and Exchange Commission (“SEC”) and bear interest at 6.25% (“Senior Notes”). The Senior Notes are unsecured and impose certain restrictive covenants, which we are subject to and currently in compliance with, including limitations on our 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 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 Senior Notes.
Indebtedness under the Senior Notes is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of their assets, which other than their investment in HEP, are not significant.

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The carrying amounts of our long-term debt are as follows:
                 
    December 31,  
    2008     2007  
    (In thousands)  
Credit Agreement
  $ 200,000     $  
 
               
Senior Notes Principal
    185,000       185,000  
Unamortized discount
    (2,344 )     (2,724 )
Fair value hedge — interest rate swap
          (841 )
Unamortized premium — dedesignated fair value hedge
    2,137        
 
           
 
    184,793       181,435  
 
           
Total debt
    384,793       181,435  
Less net short-term borrowings under credit agreement
    29,000        
 
           
Total long-term debt
  $ 355,793     $ 181,435  
 
           
Interest Rate Risk Management
As of December 31, 2008, we have three interest rate swap contracts.
We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2008. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, we measure 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 our swap against the expected future interest payments on our $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008, we had no ineffectiveness on our cash flow hedge.
We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36% as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.
In October 2008, we entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of our hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.
Our interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in our consolidated balance sheets with a corresponding entry to interest expense. For the year ended December 31, 2008, we recognized $2.3 million in interest expense attributable to fair value adjustments to our interest rate swaps.

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Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the 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 Senior Notes, effectively adjusting the carrying value this $60.0 million to its fair value. We dedesignated this hedge in October 2008. At this time, the carrying balance of our 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.
We record 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 our interest rate swaps is as follows:
                         
    Balance Sheet           Location of      
Interest Rate Swaps   Location   Fair Value     Offsetting Balance   Offsetting Amount  
                (In thousands)        
Asset
                       
Fixed-to-variable interest rate swap — $60 million of 6.25% Senior Notes
  Other assets   $ 4,079     Long-term debt   $ (2,195 )
 
              Interest expense     (1,884 )
 
                   
 
      $ 4,079         $ (4,079 )
 
                   
 
                       
Liability
                       
Cash flow hedge — $171 million LIBOR based debt
  Other long-term liabilities   $ (12,967 )   Accumulated other comprehensive income   $ 12,967  
Variable-to-fixed interest rate swap — $60 million
  Other long-term liabilities     (4,166 )   Interest expense     4,166  
 
                   
 
      $ (17,133 )       $ 17,133  
 
                   
Interest Expense and Other Debt Information
Interest expense consists of the following components:
                         
    Years Ended December 31,  
    2008     2007     2006  
        (In thousands)      
 
                       
Interest on outstanding debt:
                       
Senior Notes, net of interest on interest rate swaps
  $ 10,454     $ 11,867     $ 11,588  
Credit Agreement, net of interest on interest rate swaps
    8,705              
Net change in fair value of interest rate swaps
    2,282              
Amortization of discount and deferred issuance costs
    1,002       1,008       968  
Commitment fees
    327       414       500  
 
                 
Total interest incurred
    22,770       13,289       13,056  
Less capitalized interest
    1,007              
 
                 
Net interest expense
  $ 21,763     $ 13,289     $ 13,056  
 
                 
Cash paid for interest (1)
  $ 12,464     $ 12,316     $ 11,912  
 
                 
 
(1)   Net of cash received under our interest rate swap agreements of $3.8 million for each of the years ended December 31, 2008, 2007 and 2006.
The estimated fair value of our Senior Notes was $124.0 million at December 31, 2008.
Note 7: Commitments and Contingencies
We lease certain facilities, pipelines and rights of way under operating leases, most of which contain renewal options. The right of way agreements have various termination dates through 2053.

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As of December 31, 2008, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:
         
Year Ending      
December 31,   $000’s  
2009
  $ 6,364  
2010
    6,363  
2011
    6,346  
2012
    6,324  
2013
    6,321  
Thereafter
    22,755  
 
     
 
       
Total
  $ 54,473  
 
     
Rental expense charged to operations was $6.6 million, $6.1 million and $5.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.
We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.
Note 8: Significant Customers
All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly, Alon and BP Plc (“BP”). The major concentration of our petroleum products pipeline system’s revenues is derived from activities conducted in the southwest United States. The following table presents the percentage of total revenues generated by each of these three customers:
                         
    Years Ended December 31,
    2008   2007   2006
Holly
    72 %     60 %     59 %
Alon
    16 %     27 %     28 %
BP
    8 %     9 %     9 %
Note 9: Related Party Transactions
Holly and Alon Agreements
As of December 31, 2008, we serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline, terminal and tankage agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.
We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering in 2004 and expires in 2019 (the “Holly PTA”). Our second agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (the “Holly IPA”). And third, we have the Holly CPTA that relates to the Crude Pipelines and Tankage Assets acquired from Holly and expires on February 29, 2023.
Under the Holly PTA, Holly IPA and Holly CPTA, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or FERC index, but 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 which is reviewed periodically. Following our July 1, 2008 PPI rate adjustments, these agreements will result in minimum payments to us of $81.3 million for the twelve months ended June 30, 2009.

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We also have a 15-year pipelines and terminals agreement with Alon (the “Alon PTA”), expiring in 2020, under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate. Following the March 1, 2008 PPI adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2009 is $22.0 million.
If Holly or Alon fail to meet their minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. With the exception of the Holly CPTA, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso, Texas (the “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 our 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. Currently, we expect to complete the majority of this project in early 2009.
Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and that expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Effective March 1, 2008, the annual fee was increased from $2.1 million to $2.3 million to cover additional general and administrative services attributable to the operations of our Crude Pipelines and Tankage Assets. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.
In consideration for Holly’s assistance in obtaining our joint venture opportunity in a new 95-mile intrastate pipeline system (the “SLC Pipeline”) now under construction by Plains All American Pipeline, L.P. (“Plains”), we will pay Holly a $2.5 million finder’s fee upon the closing of our investment in the joint venture with Plains. See Note 13 for further information on this proposed joint venture.
  Pipeline, terminal and tankage revenues received from Holly were $85.0 million, $61.0 million and $52.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. These amounts include revenues received under the Holly PTA, Holly IPA and Holly CPTA.
 
  Other revenues received from Holly for the year ended December 31, 2007 were $2.7 million related to our sale of inventory of accumulated terminal overages of refined product. These overages arose from net product gains at our terminals from the beginning of 2005 through the third quarter of 2007. In the fourth quarter of 2007, we amended our pipelines and terminals agreement with Holly to provide that, on a go-forward basis, such terminal overages of refined product belong to Holly.
 
  Holly charged general and administrative services under the Omnibus Agreement of $2.2 million for the year ended December 31, 2008 and $2.0 million for each of the years ended December 31, 2007 and 2006.
 
  We reimbursed Holly for costs of employees supporting our operations of $13.1 million, $8.5 million and $7.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
 
  Holly reimbursed us $0.3 million and $0.2 million for certain costs paid on their behalf for the years ended December 31, 2007 and 2006, respectively.
 
  We distributed $25.6 million, $22.8 million and $20.3 million for the years ended December 31, 2008, 2007 and 2006, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest.

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  Our accounts receivable from Holly was $9.4 million and $5.7 million at December 31, 2008 and 2007, respectively.
 
  Our accounts payable to Holly were $2.2 million and $6.0 million at December 31, 2008 and 2007, respectively.
 
  Holly failed to meet its minimum volume commitment for each of the fourteen quarters since inception of the Holly IPA. Through December 31, 2008, we have charged Holly $7.0 million for these shortfalls of which $0.5 million and zero is included in affiliate accounts receivable at December 31, 2008 and 2007, respectively.
 
  Our revenues for the years ended December 31, 2008 and 2007 included shortfalls billed under the Holly IPA of $1.2 million in 2007 and $2.4 million in 2006, respectively, as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters in 2008 and 2007. Deferred revenue in the consolidated balance sheets at December 31, 2008 and 2007, includes $2.4 million and $1.1 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $2.4 million deferred at December 31, 2008.
Alon became a related party when it acquired all of our Class B subordinated units in connection with our acquisition of assets from them on February 28, 2005.
  Pipeline and terminal revenues received from Alon were $11.6 million, $21.8 million and $18.0 million for the years ended December 31, 2008, 2007 and 2006, respectively, under the Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement with Alon were $7.0 million, $7.1 million and $6.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.
 
  We distributed $2.8 million, $2.6 million and $2.4 million for the years ended December 31, 2008, 2007 and 2006, respectively, to Alon for distributions on its Class B subordinated units.
 
  Included in our accounts receivable — trade were $2.5 million and $3.5 million at December 31, 2008 and 2007, respectively, which represented receivable balances from Alon.
 
  Our revenues for the year ended December 31, 2008 included $2.6 million of shortfalls billed under the Alon PTA in 2007 as Alon did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at December 31, 2008 and 2007 includes $13.3 million and $2.6 million, respectively, relating to the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon PTA to allow Alon to receive credit for any of the $13.3 million deferred at December 31, 2008.
BP
We have a 70% ownership interest in Rio Grande and BP owns the other 30%. Due to the ownership interest and resulting consolidation, BP is a related party to us.
  BP’s agreement to ship on the Rio Grande pipeline expired on March 31, 2008. Rio Grande is currently serving multiple shippers on the pipeline. We recorded revenues from BP of $9.3 million, $9.2 million and $8.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.
 
  Rio Grande paid distributions to BP of $1.8 million, $1.3 million and $1.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.
 
  Included in our accounts receivable — trade at December 31, 2008 and 2007 were $2.5 million and $1.5 million, respectively, which represented the receivable balance of Rio Grande from BP.

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Note 10: Partners’ Equity, Allocations and Cash Distributions
Issuances of units
As partial consideration for our purchase of the Crude Pipelines and Tankage Assets, we issued 217,497 of our common units having a fair value of $9.0 million to Holly. Also, Holly purchased an additional 2,503 of our common units for $0.1 million and HEP Logistics Holdings, L.P., our general partner, contributed $0.2 million as an additional capital contribution in order to maintain its 2% general partner interest.
Holly currently holds 7,000,000 of our subordinated units and 290,000 of our common units, which constitutes a 46% ownership interest in us, including the 2% general partner interest. The subordination period applicable to Holly’s subordinated units extends until the first day of any quarter beginning after June 30, 2009 that certain tests based on our exceeding minimum quarterly distributions are met.
Under our registration statement filed with the SEC using a “shelf” registration process, we may offer from time to time up to $1.0 billion of our securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.
Allocations of Net Income
Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes any incentive distributions declared in the period. After the amount of incentive distributions is allocated to the general partner, the remaining net income for the period is generally allocated to the partners based on their weighted average ownership percentage during the period.
Cash Distributions
We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the Credit Agreement, occurs or would result from the cash distribution.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving Credit Agreement and in all cases are used solely for working capital purposes or to pay distributions to partners.
We make distributions of available cash from operating surplus for any quarter during any subordination period in the following manner: firstly, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; secondly, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the

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subordination period; thirdly, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.
The general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
                         
            Marginal Percentage Interest in
    Total Quarterly Distribution   Distributions
    Target Amount   Unitholders   General Partner
Minimum Quarterly Distribution
  $ 0.50       98 %     2 %
First Target Distribution
  Up to $0.55     98 %     2 %
Second Target Distribution
  above $0.55 up to $0.625     85 %     15 %
Third Target distribution
  above $0.625 up to $0.75     75 %     25 %
Thereafter
  Above $0.75     50 %     50 %
The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for each period in which declared.
                         
    2008     2007     2006  
    (in thousands, except per unit data)  
 
                       
General partner interest
  $ 1,045     $ 915     $ 850  
General partner incentive distribution
    3,098       2,191       1,182  
 
                 
 
                       
Total general partner distribution
    4,143       3,106       2,032  
Limited partner distribution
    48,283       44,868       41,638  
 
                 
 
                       
Total regular quarterly cash distribution
  $ 52,426     $ 47,974     $ 43,670  
 
                 
Cash distribution per unit applicable to limited partners
  $ 2.96     $ 2.785     $ 2.585  
 
                 
On January 27, 2009, we announced a cash distribution for the fourth quarter of 2008 of $0.765 per unit. The distribution is payable on all common, subordinated, and general partner units on February 13, 2009 to all unitholders of record on February 5, 2009. The aggregate amount of the distribution is $13.8 million, including $1.0 million to the general partner as an incentive distribution.
As a master limited partnership, we distribute our available cash, which has historically exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004 and the intermediate pipelines purchased from Holly in 2005 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $157.3 million would have been recorded as increases to our properties and equipment and intangible assets instead of reductions to our partners’ equity.
Note 11: Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows:
                                         
    First   Second   Third   Fourth   Total
            (In thousands, except per unit data)        
Year ended December 31, 2008
                                       
Revenues
  $ 27,276     $ 26,775     $ 29,511     $ 34,526     $ 118,088  
Operating income
  $ 11,950     $ 9,369     $ 10,998     $ 15,235     $ 47,552  
Net income
  $ 7,798     $ 3,815     $ 6,621     $ 7,133     $ 25,367  
Limited partners’ interest in net income
  $ 6,977     $ 3,015     $ 5,716     $ 6,116     $ 21,824  
Net income per limited partner unit — basic and diluted
  $ 0.43     $ 0.18     $ 0.35     $ 0.38     $ 1.34  
Distributions declared per limited partner unit
  $ 0.725     $ 0.735     $ 0.745     $ 0.755     $ 2.96  

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    First   Second   Third   Fourth   Total
            (In thousands, except per unit data)        
Year ended December 31, 2007
                                       
Revenues
  $ 23,872     $ 27,131     $ 27,213     $ 27,191     $ 105,407  
Operating income
  $ 10,796     $ 14,450     $ 14,274     $ 13,551     $ 53,071  
Net income
  $ 7,434     $ 11,006     $ 10,690     $ 10,141     $ 39,271  
Limited partners’ interest in net income
  $ 6,854     $ 10,280     $ 9,896     $ 9,309     $ 36,339  
Net income per limited partner unit — basic and diluted
  $ 0.43     $ 0.64     $ 0.61     $ 0.58     $ 2.26  
Distributions declared per limited partner unit
  $ 0.675     $ 0.690     $ 0.705     $ 0.715     $ 2.785  
Note 12: Supplemental Guarantor/Non-Guarantor Financial Information
Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional. Rio Grande (“Non-Guarantor”), in which we have a 70% ownership interest, is the only subsidiary that has not guaranteed these obligations.
The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Subsidiaries accounted for the ownership of the Non-Guarantor, using the equity method of accounting.

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Condensed Consolidating Balance Sheet
                                         
            Guarantor     Non-              
December 31, 2008   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
Current assets:
                                       
Cash and cash equivalents
  $ 2     $ 3,706     $ 1,561     $     $ 5,269  
Accounts receivable
          13,332       1,145             14,477  
Intercompany accounts receivable (payable)
    (197,828 )     197,979       (151 )            
Prepaid and other current assets
    176       417                   593  
 
                             
Total current assets
    (197,650 )     215,434       2,555             20,339  
 
                                       
Properties and equipment, net
          257,886       32,398             290,284  
Investment in subsidiaries
    378,481       23,842             (402,323 )      
Transportation agreements, net
          122,383                   122,383  
Other assets
    5,300       1,382                   6,682  
 
                             
Total assets
  $ 186,131     $ 620,927     $ 34,953     $ (402,323 )   $ 439,688  
 
                             
 
                                       
LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)
                                       
Current liabilities:
                                       
Accounts payable
  $     $ 7,357     $ 661     $     $ 8,018  
Accrued interest
    (27,778 )     30,623                   2,845  
Deferred revenue
          15,658                   15,658  
Accrued property taxes
          1,015       130             1,145  
Other current liabilities
    31,214       (29,811 )     102             1,505  
Short-term borrowings under credit agreement
          29,000                   29,000  
 
                             
Total current liabilities
    3,436       53,842       893             58,171  
 
                                       
Long-term debt
    184,793       171,000                   355,793  
Other long-term liabilities
          17,604                   17,604  
Minority interest
                      10,218       10,218  
Partners’ equity (deficit)
    (2,098 )     378,481       34,060       (412,541 )     (2,098 )
 
                             
Total liabilities and partners’ equity (deficit)
  $ 186,131     $ 620,927     $ 34,953     $ (402,323 )   $ 439,688  
 
                             
Condensed Consolidating Balance Sheet
                                         
            Guarantor     Non-              
December 31, 2007   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
Current assets:
                                       
Cash and cash equivalents
  $ 2     $ 8,060     $ 2,259     $     $ 10,321  
Accounts receivable
          10,820       1,491             12,311  
Intercompany accounts receivable (payable)
    (141,175 )     141,553       (378 )            
Prepaid and other current assets
    183       363                   546  
 
                             
Total current assets
    (140,990 )     160,796       3,372             23,178  
 
                                       
Properties and equipment, net
          125,383       33,217             158,600  
Investment in subsidiaries
    353,235       25,059             (378,294 )      
Transportation agreements, net
          54,273                   54,273  
Other assets
    1,302       1,551                   2,853  
 
                             
Total assets
  $ 213,547     $ 367,062     $ 36,589     $ (378,294 )   $ 238,904  
 
                             
 
                                       
LIABILITIES AND PARTNERS’ EQUITY
                                       
Current liabilities:
                                       
Accounts payable
  $     $ 8,499     $ 533     $     $ 9,032  
Accrued interest
    (2,932 )     5,928                   2,996  
Deferred revenue
          3,700                   3,700  
Accrued property taxes
          1,021       156             1,177  
Other current liabilities
    6,387       (5,661 )     101             827  
 
                             
Total current liabilities
    3,455       13,487       790             17,732  
 
                                       
Long-term debt
    181,435                         181,435  
Other long-term liabilities
    841       340                   1,181  
Minority interest
                      10,740       10,740  
Partners’ equity
    27,816       353,235       35,799       (389,034 )     27,816  
 
                             
Total liabilities and partners’ equity
  $ 213,547     $ 367,062     $ 36,589     $ (378,294 )   $ 238,904  
 
                             

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Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Year ended December 31, 2008   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 85,040     $     $     $ 85,040  
Third parties
          25,077       9,266       (1,295 )     33,048  
 
                             
 
          110,117       9,266       (1,295 )     118,088  
 
                                       
Operating costs and expenses:
                                       
Operations
          38,936       3,629       (1,295 )     41,270  
Depreciation and amortization
          21,529       1,360             22,889  
General and administrative
    3,819       2,561       (3 )           6,377  
 
                             
 
    3,819       63,026       4,986       (1,295 )     70,536  
 
                             
Operating income (loss)
    (3,819 )     47,091       4,280             47,552  
 
                                       
Equity in earnings of subsidiaries
    38,215       2,983             (41,198 )      
Interest income (expense)
    (9,029 )     (12,621 )     46             (21,604 )
Gain on sale of assets
          1,032                   1,032  
Minority interest
                      (1,278 )     (1,278 )
 
                             
 
    29,186       (8,606 )     46       (42,476 )     (21,850 )
 
                             
Income before income taxes
    25,367       38,485       4,326       (42,476 )     25,702  
 
                                       
State income tax
          (270 )     (65 )           (335 )
 
                             
 
                                       
Net income
  $ 25,367     $ 38,215     $ 4,261     $ (42,476 )   $ 25,367  
 
                             
Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Year ended December 31, 2007   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 63,709     $     $     $ 63,709  
Third parties
          33,720       9,217       (1,239 )     41,698  
 
                             
 
          97,429       9,217       (1,239 )     105,407  
 
                                       
Operating costs and expenses:
                                       
Operations
          30,523       3,627       (1,239 )     32,911  
Depreciation and amortization
          12,520       1,862             14,382  
General and administrative
    2,730       2,135       178             5,043  
 
                             
 
    2,730       45,178       5,667       (1,239 )     52,336  
 
                             
Operating income (loss)
    (2,730 )     52,251       3,550             53,071  
 
                                       
Equity in earnings of subsidiaries
    54,362       2,487             (56,849 )      
Interest income (expense)
    (12,361 )     (474 )     79             (12,756 )
Gain on sale of assets
          298                   298  
Minority interest
                      (1,067 )     (1,067 )
 
                             
 
    42,001       2,311       79       (57,916 )     (13,525 )
 
                             
Income before income taxes
    39,271       54,562       3,629       (57,916 )     39,546  
 
                             
 
                                       
State income tax
          (200 )     (75 )           (275 )
 
                             
 
                                       
Net income
  $ 39,271     $ 54,362     $ 3,554     $ (57,916 )   $ 39,271  
 
                             
Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Year ended December 31, 2006   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 52,878     $     $     $ 52,878  
Third parties
          29,119       8,400       (1,203 )     36,316  
 
                             
 
          81,997       8,400       (1,203 )     89,194  
 
                                       
Operating costs and expenses:
                                       
Operations
          27,009       2,824       (1,203 )     28,630  
Depreciation and amortization
          11,933       3,397             15,330  
General and administrative
    2,794       2,055       5             4,854  
 
                             
 
    2,794       40,997       6,226       (1,203 )     48,814  
 
                             
Operating income (loss)
    (2,794 )     41,000       2,174             40,380  
 
                                       
Equity in earnings of subsidiaries
    42,456       1,588             (44,044 )      
Interest expense
    (12,119 )     (132 )     94             (12,157 )
Minority interest
                      (680 )     (680 )
 
                             
 
                                       
Net income
  $ 27,543     $ 42,456     $ 2,268     $ (44,724 )   $ 27,543  
 
                             

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Condensed Consolidating Statement of Cash Flows
                                         
            Guarantor     Non-              
Year Ended December 31, 2008   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Cash flows from operating activities
  $ 44,035     $ 17,973     $ 5,843     $ (4,200 )   $ 63,651  
 
                                       
Cash flows from investing activities
                                       
Additions to properties and equipment
          (41,762 )     (541 )           (42,303 )
Acquisition of crude pipelines and tankage assets
          (171,000 )                 (171,000 )
Proceeds from sale of assets
          36                   36  
 
                             
 
          (212,726 )     (541 )           (213,267 )
 
                             
Cash flows from financing activities
                                       
Net borrowings under credit agreement
    9,000       191,000                   200,000  
Proceeds from issuance of common units
          104                   104  
Contribution from general partner
    186                         186  
Distributions to partners
    (52,426 )           (6,000 )     6,000       (52,426 )
Cash distributions to minority interest
                      (1,800 )     (1,800 )
Purchase of units for restricted unit grants
    (795 )                       (795 )
Deferred financing costs
          (705 )                 (705 )
 
                             
 
    (44,035 )     190,399       (6,000 )     4,200       144,564  
 
                             
Cash and cash equivalents
                                       
Decrease for the year
          (4,354 )     (698 )           (5,052 )
Beginning of year
    2       8,060       2,259             10,321  
 
                             
End of year
  $ 2     $ 3,706     $ 1,561     $     $ 5,269  
 
                             
Condensed Consolidating Statement of Cash Flows
                                         
            Guarantor     Non-              
Year Ended December 31, 2007   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Cash flows from operating activities
  $ 49,056     $ 6,784     $ 6,226     $ (3,010 )   $ 59,056  
 
                                       
Cash flows from investing activities
                                       
Additions to properties and equipment
          (8,556 )     (1,401 )           (9,957 )
Proceeds from sale of assets
          325                   325  
 
                             
 
          (8,231 )     (1,401 )           (9,632 )
 
                             
Cash flows from financing activities
                                       
Distributions to partners
    (47,974 )           (4,300 )     4,300       (47,974 )
Cash distributions to minority interest
                      (1,290 )     (1,290 )
Purchase of units for restricted unit grants
    (1,082 )                       (1,082 )
Deferred financing costs
          (296 )                 (296 )
Other
          (16 )                 (16 )
 
                             
 
    (49,056 )     (312 )     (4,300 )     3,010       (50,658 )
 
                             
Cash and cash equivalents
                                       
Increase (decrease) for the year
          (1,759 )     525             (1,234 )
Beginning of year
    2       9,819       1,734             11,555  
 
                             
End of year
  $ 2     $ 8,060     $ 2,259     $     $ 10,321  
 
                             
Condensed Consolidating Statement of Cash Flows
                                         
            Guarantor     Non-              
Year Ended December 31, 2006    Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Cash flows from operating activities
  $ 44,304     $ 930     $ 4,049     $ (3,430 )   $ 45,853  
 
                                       
Cash flows from investing activities — additions to properties and equipment
          (8,881 )     (226 )           (9,107 )
 
                                       
Cash flows from financing activities
                                       
Distributions to partners
    (43,670 )           (4,900 )     4,900       (43,670 )
Cash distributions to minority interest
                      (1,470 )     (1,470 )
Purchase of units for restricted unit grants
    (634 )                       (634 )
 
                             
 
    (44,304 )           (4,900 )     3,430       (45,774 )
 
                             
Cash and cash equivalents
                                       
Decrease for the year
          (7,951 )     (1,077 )           (9,028 )
Beginning of year
    2       17,770       2,811             20,583  
 
                             
End of year
  $ 2     $ 9,819     $ 1,734     $     $ 11,555  
 
                             

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Note 13: Proposed Joint Venture
In November 2007, we 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 us. We expect to purchase our 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 Holly’s 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 our investment in the SLC Pipeline is expected to be $28.0 million, including the $2.5 million finder’s fee that is payable to Holly upon the closing of our investment in the SLC Pipeline.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We have had no change in, or disagreement with, our independent registered public accounting firm on matters involving accounting and financial disclosure.
Item 9A. Controls and Procedures
(a) Evaluation of disclosure controls and procedures
Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
(b) 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 Registered Public Accounting Firm.”
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2008 that would need to be reported on Form 8-K that have not been previously reported.

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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Holly Logistic Services, L.L.C., as the general partner of HEP Logistics Holdings, L.P., our general partner, manages our operations and activities on our behalf. Our general partner is not elected by our unitholders. Unitholders are not entitled to elect the directors of HLS or directly or indirectly participate in our management or operation. The sole member of HLS, which is a subsidiary of Holly, elects our directors to serve until their death, resignation or removal. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.
Three members of the board of directors of HLS serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of HLS or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the New York Stock Exchange and the Exchange Act to serve on the audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we have an audit committee of three independent directors that reviews our external financial reporting, selects our independent registered public accounting firm, and reviews procedures for internal auditing and the adequacy of our internal accounting controls. We also have a compensation committee consisting of the three independent directors, which oversees compensation decisions for certain officers of HLS whose time is fully committed to us and a portion of the long-term incentive compensation of other officers who only devote part of their time to the matters of HEP and who receive long-term incentive compensation with respect to their services. The compensation committee also oversees the compensation plans described below. In addition, we have an executive committee of the board consisting of one independent director and two directors employed by Holly.
The board of directors of HLS has determined that Messrs. Darling, Pinkerton and Stengel meet the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange and under the Exchange Act. These directors serve as the only members of our audit, conflicts and compensation committees.
Mr. Darling has been selected to preside at regularly scheduled meetings of non-management directors. Persons wishing to communicate with the non-management directors are invited to email the Presiding Director at presiding.director@hollyenergypartners.com or write to: Charles M. Darling, IV, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915.
The board of directors of HLS held twelve meetings during 2008, with the audit committee, conflicts committee and compensation committee holding seven, seven and ten meetings, respectively. During 2008, each director attended at least 75% of the total number of meetings of the board. With the exception of two directors who each was absent from one board meeting, all board members attended each board meeting in 2008. All committee members attended each committee meeting for the committees on which they serve.
We are managed and operated by the directors and officers of HLS on behalf of our general partner. Most of our operational personnel are employees of HLS.
Mr. Clifton spends approximately 25% of his time overseeing the management of our business and affairs. Messrs. Blair and Cunningham spend all of their time in the management of our business. The rest of our officers devote approximately one-quarter of their time to us. Our non-management directors

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devote as much time as is necessary to prepare for and attend board of directors and committee meetings.
The following table shows information for the current directors and executive officers of HLS.
             
Name   Age   Position with HLS
Matthew P. Clifton
    57     Chairman of the Board and Chief Executive Officer1
David G. Blair
    50     Senior Vice President
Bruce R. Shaw
    41     Senior Vice President and Chief Financial Officer
Mark T. Cunningham
    49     Vice President, Operations
Denise C. McWatters
    49     Vice President, General Counsel and Secretary
P. Dean Ridenour
    67     Director
Charles M. Darling, IV
    60     Director2 3 4
William J. Gray
    68     Director
Jerry W. Pinkerton
    68     Director1 2 3 4
William P. Stengel
    60     Director1 2 3 4
 
1   Member of the Executive Committee
 
2   Member of the Conflicts Committee
 
3   Member of the Audit Committee
 
4   Member of the Compensation Committee
Matthew P. Clifton was elected Chairman of our Board, and Chief Executive Officer in March 2004. He has been employed by Holly for over twenty years. Mr. Clifton served as Holly’s Vice President of Economics, Engineering and Legal Affairs from 1988 to 1991, Senior Vice President of Holly from 1991 to 1995, President of Navajo Pipeline Company, a wholly owned subsidiary of Holly, since its inception in 1981, President of Holly from 1995 to 2005 and has served as Chief Executive Officer of Holly since January 1, 2006. Mr. Clifton has also served as a director of Holly since 1995.
David G. Blair was elected Senior Vice President in January 2007. He has been employed by Holly for over 27 years. Mr. Blair served as Holly’s Vice President responsible for Holly Asphalt Company from February 2005 to December 2006. Mr. Blair was General Manager of the NK Asphalt Partnership between Koch Materials Company and Navajo Refining Company from July 2000 to February 2005. Mr. Blair was named Vice President, Marketing, Asphalt & Specialty Products in October 1994. Mr. Blair served in various positions within Holly in crude oil supply, wholesale product marketing, and supply and trading from 1981 to 1991.
Bruce R. Shaw was elected to the position of Senior Vice President, Chief Financial Officer in January 2008. Mr. Shaw served on our Board of Directors from April 2007 to April 2008 and as Vice President, Special Projects for Holly from September 2007 to December 2007. Prior to September 2007, Mr. Shaw briefly left Holly in June 2007 and served as President of Standard Supply and Distributing Company, Inc. and Bartos Industries, Ltd., two companies that are affiliated with each other in the heating, ventilation, and air conditioning industry. Mr. Shaw previously served Holly in various positions including Vice President of Corporate Development from February 2006 to May 2007, Vice President of Crude Purchasing and Corporate Development from February 2005 to February 2006, Vice President of Corporate Development from March 2004 to February 2005, Vice President of Marketing and Corporate Development from November 2003 to March 2004, Vice President of Corporate Development from October 2001 to November 2003 and Director of Corporate Development from June 1997 to January 2000. Mr. Shaw also served as Vice President, Corporate Development for HLS from August 2004 to January 2007.
Mark T. Cunningham was elected Vice President of Operations in July of 2007. He has served Holly as Senior Manager of Special Projects from December 2006 through June 2007 and as Senior Manager of Integrity Management and EH&S from July 2004 through December 2006. Prior to joining Holly, Mr. Cunningham served Diamond Shamrock / Ultramar Diamond Shamrock for 20 years in several engineering and pipeline operations capacities. He began his time with Diamond Shamrock in 1983 and

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served various positions including Senior Design Engineer, Superintendent of Special Projects, Regional Manager and General Manager of Operations and Director of Operations through April 2003.
Denise C. McWatters was promoted to Vice President, General Counsel and Secretary of Holly Logistic Services, LLC and Holly Corporation effective May 12, 2008. She joined Holly in October 2007 as Deputy General Counsel with more than 20 years of legal experience. Ms. McWatters served as the General Counsel of The Beck Group from May 2005 through October 2007. Prior to joining Beck, Ms. McWatters was a shareholder in the predecessor to Locke Lord Bissell & Liddell LLP, served as Counsel in the legal department at Citigroup, N.A. and was a shareholder in Cox Smith Matthews Incorporated.
P. Dean Ridenour was elected to our Board of Directors in August 2004 and served as Vice President and Chief Accounting Officer from January 2005 to January 2008. Mr. Ridenour served as Vice President, Special Projects of Holly Corporation from August 2004 to December 2004 and prior to becoming a full-time employee, provided full-time consulting services to Holly Corporation beginning in October 2002. From April 2001 until October 2002, Mr. Ridenour was temporarily retired. From July 1999 through April 2001, Mr. Ridenour served as Chief Financial Officer and director of GeoUtilities, Inc., an internet-based superstore for energy, telecom and other utility services, which was purchased by AES Corporation in March 2000. Mr. Ridenour was employed for 34 years by Ernst & Young LLP, including 20 years as an audit partner, retiring in 1997. Mr. Ridenour is no longer an officer of HEP.
Charles M. Darling, IV was elected to our Board of Directors in July 2004. Mr. Darling has served as President of DQ Holdings, L.L.C., a venture capital investment and consulting firm focused primarily on opportunities in the energy industry, since August 1998. From 1997 to 1998, Mr. Darling was the President and General Counsel, and was a Director from 1993 to 1998, of DeepTech International, which was acquired by El Paso Energy Corp. in August 1998. Mr. Darling was also a Director at Leviathan Gas Pipeline Company from 1993 through 1998. Prior to joining DeepTech in 1997, Mr. Darling practiced law at the law firm of Baker Botts, L.L.P., for over 20 years.
William J. Gray was elected to our Board of Directors in April 2008. Mr. Gray is a private consultant and served as a director of Holly Corporation from September 1996 until May 2008. He has also served as a governmental affairs consultant for Holly Corporation since January 2003 and as a consultant to Holly from October 1999 through September 2001. Until October 1999, Mr. Gray was Senior Vice President, Marketing and Supply of Holly Corporation. In November 2006, Mr. Gray was elected to the New Mexico House of Representatives.
Jerry W. Pinkerton was elected to our Board of Directors in July 2004. Since December 2003, Mr. Pinkerton has been retired. From December 2000 to December 2003, Mr. Pinkerton served as a consultant to TXU Corp and from August 1997 to December 2000, Mr. Pinkerton served as Controller of TXU and its U.S. subsidiaries. From August 1988 until its merger with TXU in August 1997, Mr. Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH Corporation. Prior to joining ENSERCH, Mr. Pinkerton was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner. Mr. Pinkerton also sits on the board of directors of Animal Health International, Inc. where he serves as chairman of its audit committee.
William P. Stengel was elected to our Board of Directors in July 2004. Mr. Stengel has been retired since May 2003. From 1997 to May 2003, Mr. Stengel served as Managing Director of the global energy and mining group at Citigroup/Citibank, N.A. From 1973 to 1997, Mr. Stengel served in various other capacities with Citigroup/Citibank, N.A.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10% of HEP’s units to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of HEP’s equity securities. Based on a review of these reports, other information available to us and written representations from reporting persons indicating that no other reports were required, all such reports concerning beneficial ownership were filed

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in a timely manner by reporting persons during the year ended December 31, 2008, except for two Form 4’s filed on January 9, 2008. These Form 4’s related to sales of HEP common units held by David G. Blair and Stephen J. McDonnell to satisfy tax withholding obligations with respect to the vesting of certain restricted units on January 1, 2008.
Audit Committee
HLS’s audit committee is composed of three directors who are not officers or employees of HEP or any of its subsidiaries or Holly Corporation or any of its subsidiaries. The board of directors of HLS has adopted a written charter for the audit committee. The board of directors of HLS has determined that a member of the audit committee, namely Jerry W. Pinkerton, is an audit committee financial expert (as defined by the SEC) and has designated Mr. Pinkerton as the audit committee financial expert. As indicated above, the board of directors of HLS has determined that Mr. Pinkerton meets the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange and under the Exchange Act.
The audit committee selects our independent registered public accounting firm and reviews the professional services they provide. It reviews the scope of the audit performed by the independent registered public accounting firm, the audit report issued by the independent auditor, HEP’s annual and quarterly financial statements, any material comments contained in the auditor’s letters to management, HEP’s internal accounting controls and such other matters relating to accounting, auditing and financial reporting as it deems appropriate. In addition, the audit committee reviews the type and extent of any non-audit work to be performed by the independent registered public accounting firm and its compatibility with their continued objectivity and independence.
Report of the Audit Committee for the Year Ended December 31, 2008
Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.’s internal controls and the financial reporting process. The audit committee selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the Partnership for the year ended December 31, 2008. Ernst & Young LLP is responsible for performing an independent audit of Holly Energy Partners, L.P.’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and to issue a report thereon as well as to issue a report on the effectiveness of Holly Energy Partners, L.P.’s internal control over financial reporting. The audit committee monitors and oversees these processes.
The audit committee has reviewed and discussed Holly Energy Partners, L.P.’s audited consolidated financial statements with management and Ernst & Young LLP. The audit committee has discussed with Ernst & Young LLP the matters required to be discussed by Statement on Auditing Standards No. 114, “The Auditor’s Communication With Those Charged With Governance.” The audit committee has received the written disclosures and the letter from Ernst & Young LLP pursuant to Rule 3526 of the Public Company Accounting Oversight Board, “Communication With Audit Committees Governing Independence,” and has discussed with Ernst & Young LLP that firm’s independence.
The board of directors of our general partner, upon recommendation by the audit committee, has adopted an audit committee charter, which is available on our website at www.hollyenergy.com. The charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All fees for audit, audit-related and tax services as well as all other fees presented under Item 14 “Principal Accountant Fees and Services” were approved by the audit committee in accordance with the charter.
Based on the foregoing review and discussions and such other matters the audit committee deemed relevant and appropriate, the audit committee recommended to the board of directors that the audited consolidated financial statements of Holly Energy Partners, L.P. be included in Holly Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2008.
Members of the Audit Committee:
Jerry W. Pinkerton, Chairman
Charles M. Darling, IV
William P. Stengel

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Code of Ethics
HEP has adopted a Code of Business Conduct and Ethics that applies to all officers, directors and employees, including the company’s principal executive officer, principal financial officer, and principal accounting officer.
Available on our website at www.hollyenergy.com are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics, all of which also will be provided in print without charge upon written request to the Vice President, Investor Relations at: Holly Energy Partners, L.P., 100 Crescent Court, Suite 1600, Dallas, TX, 75201-6915. The Partnership intends to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of its Code of Business Conduct and Ethics with respect to its principal financial officers by posting such information on this website.
New York Stock Exchange Certification
In 2008, Mr. Clifton, as the Company’s Chief Executive Officer, provided to the New York Stock Exchange the annual CEO certification regarding the Company’s compliance with the New York Stock Exchange’s corporate governance listing standards.

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Item 11. Executive Compensation
DIRECTOR COMPENSATION
Members of the Board of Directors of HLS who also serve as officers or employees of HLS or Holly do not receive additional compensation in their capacity as directors. The only officers of HLS or Holly who also served as directors during 2008 were Messrs. Clifton, Shaw and Ridenour. Mr. Shaw was a director until April, 2008. Mr. Gray was elected to replace Mr. Shaw as a member of the HLS Board of Directors on April 15, 2008. Mr. Ridenour was an employee of Holly during 2008 until March 31, 2008 when he retired but continued to provide limited services to Holly under a consulting agreement. Mr. Ridenour is no longer an employee and he no longer serves as an officer of HLS.
In 2008, the compensation for non-employee directors of HLS was: (a) a $50,000 annual cash retainer, payable in four quarterly installments; (b) $1,500 for attendance at each in-person meeting of the Board of Directors or a Board committee, a $1,000 meeting fee for attendance at each telephonic meeting of the Board of Directors or a Board committee that lasts more than thirty minutes, and a fee of $1,500 per day for each day that a non-employee director attends a strategy meeting with the HLS management; (c) an annual grant under the Holly Energy Partners, L.P. Long-Term Incentive Plan (“Long-Term Incentive Plan”) of restricted HEP units equal in value to $50,000 on the date of grant, with 100% vesting one year after the date of grant. The Long-Term Incentive Plan grants are effective on the date they are approved by the Board of Directors and this date varies each year. A restricted HEP unit is a common unit subject to forfeiture until the award vests. Each director receiving restricted HEP units is a unitholder with respect to all of the restricted HEP units and has the right to receive all distributions paid with respect to such units. In addition, the directors who serve as chairpersons of the committees of the Board of Directors each receive an annual retainer of $10,000, payable in four quarterly installments. On July 25, 2008, the Board of Directors approved the payment of a cash meeting fee to non-employee directors for attending any meetings of a committee of the Board of Directors of which the non-employee director is not a member, when such committee meeting attendance is at the request of the chairman of the committee, with the amount of such meeting fee being the same as the meeting fee payable to non-employee directors who are committee members in attendance at the same meeting. Directors are reimbursed for out-of-pocket expenses in connection with attending board or committee meetings. Each director is fully indemnified by HLS for actions associated with being a director to the extent permitted under Delaware law.
During the calendar year ending December 31, 2008, compensation was made to directors of HLS as set forth below:
                         
    Fees Earned or   Stock    
    Paid in Cash(1)   Awards(2)   Total
Charles M. Darling, IV
  $ 101,000     $ 57,711     $ 158,711  
William Gray (3)
  $ 40,000     $ 26,101     $ 66,101  
Jerry W. Pinkerton
  $ 101,000     $ 57,711     $ 158,711  
P. Dean Ridenour (4)
  $ 47,500     $ 27,838 (2)   $ 75,338  
Bruce R. Shaw (5)
    0     $ 29,063     $ 29,063  
William P. Stengel
  $ 101,000     $ 57,711     $ 158,711  
 
(1)   The number in the chart reflects total 2008 cash compensation. An insignificant portion of this amount was paid in January, 2009, due to a delay in processing payment for certain December meeting fees.
 
(2)   Reflects the amount recognized in the year ended December 31, 2008 in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share Based payments, and includes amounts for awards granted prior to 2008. Messrs. Stengel, Pinkerton and Darling each received an award of 1,466 restricted HEP units on August 1, 2008 with a grant date fair value of $50,000. Mr. Gray received an award of 1,833 restricted HEP units on August 1, 2008 with a grant date fair value of $62,500. Mr. Ridenour received an award of 1,955 restricted HEP units on August 1, 2008 with a grant date fair value of $66,667. The equity awards to Mr. Gray and Mr. Ridenour include additional compensation ($12,500 and $16,667, respectively) for service as outside directors during the period that commenced

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    after the award of restricted units to directors on August 1, 2007 but prior to the award of restricted units to directors on August 1, 2008. The restricted HEP units granted on August 1, 2008 will vest on August 1, 2009. The fair market value of each restricted unit grant is measured on the grant date and is amortized over the vesting period. As of December 31, 2008, Messrs. Darling, Pinkerton and Stengel each held 1,466 unvested restricted units, Mr. Gray held 1,833 unvested restricted units and Mr. Ridenour held 1,955 unvested restricted units.
 
(3)   In addition to the $40,000 of director fees reflected in this table, Mr. Gray received cash compensation for consulting services provided by Mr. Gray to Holly Corporation during 2008. None of the consulting fees were paid by HEP.
 
(4)   The director compensation described for P. Dean Ridenour is also included in the Summary Compensation Table since Mr. Ridenour was one of our officers through January 7, 2008.
 
(5)   This represents 2008 amounts accrued for the 2007 restricted HEP units awarded to Mr. Shaw while he was an outside director. Mr. Shaw was not paid for services as a director in 2008 since he was also an officer.
COMPENSATION DISCUSSION AND ANALYSIS
This compensation discussion and analysis (“CD&A”) provides information about our compensation objectives and policies for the HLS officers that also act as our principal executive officer, our principal financial officer and our other most highly compensated executive officers and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. We provide a general description of our compensation program and specific information about its various components. Additionally, we describe our policies relating to reimbursement to Holly for compensation expenses. We also provide information about HLS executive officer changes that became effective in January 2008, where applicable. Immediately following this CD&A is our Compensation Committee Report (the “Committee Report”).
Overview
HEP is managed by HLS, the general partner of HEP’s general partner. HLS is a subsidiary of Holly. The employees providing services to HEP are employed by HLS; HEP itself has no employees. As of December 31, 2008, HLS had 121 employees that provide general, administrative and operational services to HEP. Throughout this discussion, the following individuals are referred to as the “Named Executive Officers” and are included in the Summary Compensation Table:
Matthew P. Clifton, HLS’s Chairman of the Board and Chief Executive Officer;
Stephen J. McDonnell, HLS’s Vice President and Chief Financial Officer until January 7, 2008 and Assistant to the Chairman from January 7, 2008 through and including January 1, 2009 when he retired;
Bruce R. Shaw, Senior Vice President and Chief Financial Officer effective January 7, 2008;
P. Dean Ridenour, HLS’s Vice President and Chief Accounting Officer until January 7, 2008. Mr. Ridenour continued to serve as a Holly employee until his retirement on March 31, 2008 and no longer served as an officer of HLS. He continues to provide limited services to Holly pursuant to a consulting agreement and is a member of the Board of Directors of HLS, but he is no longer an HLS or Holly employee.
David G. Blair, HLS’s Senior Vice President; and
Mark T. Cunningham, HLS’s Vice President, Operations.

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Of the six Named Executive Officers of HEP, only Messrs. Blair and Cunningham are current employees of HLS.
Under the terms of the Omnibus Agreement, the annual administrative fee we pay to Holly increased to $2,300,000 as of March 1, 2008 and is for the provision of general and administrative services for our benefit, which may be increased as permitted under the Omnibus Agreement. Additionally, we reimburse Holly for expenses incurred on our behalf. The administrative services covered by the Omnibus Agreement include, without limitation, the costs of corporate services provided to HEP by Holly such as accounting, information technology, human resources and in-house legal support; office space, furnishings and equipment; and transportation of HEP executive officers and employees on Holly airplanes for business purposes. The partnership agreement provides that our general partner will determine the expenses that are allocable to HEP. See Item 13, “Certain Relationships and Related Transactions” of this Form 10-K Annual Report for additional discussion of our relationships and transactions with Holly. None of the services covered by the administrative fee are assigned any particular value individually. Although certain Named Executive Officers provide services to both Holly and HEP, no portion of the administrative fee is specifically allocated to services provided by the Named Executive Officers to HEP; rather, the administrative fee generally covers services provided to HEP by Holly and HLS employees and, except as described below, there is no reimbursement by HEP of cash compensation expenses paid by Holly or HLS to the Named Executive Officers. With respect to equity compensation paid by HEP to the Named Executive Officers, HLS purchases the units, and HEP reimburses HLS for the purchase price.
With respect to Messrs. Blair and Cunningham, we reimbursed Holly for 100% of the compensation expenses incurred by Holly for salary, bonus, retirement and other benefits for 2008 for Messrs. Blair and Cunningham. We reimbursed HLS for 100% of the expenses incurred in providing Messrs. Blair and Cunningham with long-term equity incentive compensation. All compensation paid to them is fully disclosed in the tabular disclosure following this CD&A.
Messrs. Clifton, McDonnell, Shaw and Ridenour were compensated by HLS for the services they perform for HLS through awards of equity-based compensation granted pursuant to the Long-Term Incentive Plan. None of the cash compensation paid to or other benefits made available to Messrs. Clifton, McDonnell, Shaw and Ridenour by Holly was allocated to the services they provide to HLS and, therefore, only the Long-Term Incentive Plan awards granted to them are disclosed herein. In 2008, Mr. Ridenour did not receive HEP equity awards for employee service but did receive equity awards for service as a director.
Objectives of Compensation Program
Our compensation program is designed to attract and retain talented and productive executives who are motivated to protect and enhance the long-term value of HEP for its unitholders. Our objective is to be competitive with our industry and encourage high levels of performance.
The HLS Compensation Committee (the “Committee”), comprised entirely of independent directors, administers the Long-Term Incentive Plan for certain HLS employees and reviewed and confirmed in February 2008 the recommendations of the Holly Compensation Committee with regard to the total compensation of Messrs. Clifton, McDonnell and Shaw. The Committee determined and approved the long-term equity incentive compensation to be paid to the Named Executive Officers and the compensation in addition to the long-term equity incentive compensation to be paid to Mr. Blair.
As to Mr. Blair, the Committee has not adopted any formal policies for allocating compensation among salaries, bonuses and long-term equity incentive compensation. The Committee attempts to balance the use of both cash and equity compensation in the total compensation package provided to Mr. Blair and as to our other Named Executive Officers, attempts to utilize long-term equity incentive compensation to build value to both HEP and its unitholders. The Committee considers recommendations by management and many other factors in deciding on the final compensation factors for which it has responsibility for each Named Executive Officer. The Committee does not review or approve pension benefits for Named Executive Officers and all are provided the same pension benefits that are provided to Holly employees.

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Mr. Cunningham’s position is a grade that does not require Committee approval of cash compensation, so his compensation package is reviewed and approved by management instead of the Committee. Mr. Cunningham’s compensation is established by Messrs. Clifton and Blair with the assistance of the Vice President of Human Resources based upon all of the same factors used by the Committee and described below. The Committee was provided with an overview of Mr. Cunningham’s compensation with opportunity to request changes to the compensation and the Committee completed its review and agreed with management’s recommendations.
In February 2008, the Committee, with the assistance of management, sought to designate an appropriate mix of cash and long-term equity incentive compensation for Messrs. Blair and Cunningham with a goal to provide sufficient current compensation to retain them, while at the same time providing incentives to maximize long-term value for HEP and its unit holders. The Committee, with the assistance of management, annually performs an i