Holly Energy Partners (HEP) 10-K 2006 FY Annual report

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, 2006

Commission File Number1-32225

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.

Yeso     Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yeso      Noþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ      Noo

Indicate by check mark 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 the Form 10-K or any amendments to the Form 10-K.

þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filero      Accelerated filerþ      Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso      Noþ

The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $327 million on June 30, 2006, 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 9, 2007 was 8,170,000.

DOCUMENTS INCORPORATED BY REFERENCE:None

TABLE OF CONTENTS

Item		Page
	PART I
Forward-Looking Statements			3
1.	Business		5
1A.	Risk factors		14
1B.	Unresolved staff comments		20
2.	Properties		20
3.	Legal proceedings		27
4.	Submission of matters to a vote of security holders		27
	PART II
5.	Market for the Registrant’s common units, related unitholder matters and issuer purchases of common units		28
6.	Selected financial data		30
7.	Management’s discussion and analysis of financial condition and results of operations		32
7A.	Quantitative and qualitative disclosures about market risk		51
8.	Financial statements and supplementary data		52
9.	Changes in and disagreements with accountants on accounting and financial disclosure		84
9A.	Controls and procedures		84
9B.	Other information		84
	PART III
10.	Directors, executive officers and corporate governance		85
11.	Executive compensation		90
12.	Security ownership of certain beneficial owners and management and related unitholder matters		106
13.	Certain relationships, related transactions and director independence		107
14.	Principal accountant fees and services		111
	PART IV
15.	Exhibits and financial statement schedules		112
Signatures			117
Statement of Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of Registrant
Consent of Independent Registered Public Accounting Firm
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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PART I

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business”, “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 belief and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could 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 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 any future acquired operations;

• The availability and cost of our 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
BP	16
bpd	6
Credit Agreement	10
Distributable cash flow	37
DOT	11
EBITDA	31
FASB	49
FERC	12
GAAP	31
HEP	5
HLS	5
Holly	5
Holly IPA	5
Holly PTA	5
Intermediate Pipelines	5
LIBOR	46
LPG	6
Maintenance capital expenditures	31
mbbls	21
mbpd	38
Navajo Refinery	5
NPL	5
Omnibus Agreement	7
Plains	10
Plains Pipeline	25
PPI	7
Purchase Agreement	9
Rio Grande	5
SEC	5
Senior Notes	8
SFAS	49
ULSD	38
Valero	25

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 pipelines 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.

HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). On July 7, 2004, we priced 6,100,000 common units for the initial public offering and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters.

On February 28, 2005, we closed on a contribution agreement with Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) that provided for our acquisition of four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas. On July 8, 2005, we closed on a purchase agreement to acquire Holly’s two 65-mile parallel intermediate feedstock pipelines (the “Intermediate Pipelines”) which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities (collectively, the “Navajo Refinery”).

We generate revenues by charging tariffs for transporting petroleum products 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 two 15-year pipeline and terminal 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 and expires in 2019 (“Holly PTA”). Our other agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (“Holly IPA”). We also serve Alon’s Big Spring Refinery under the Alon Pipelines and Terminals Agreement expiring 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 780 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;

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• approximately 510 miles of refined product pipelines that transport refined products from Alon’s Big Spring Refinery in Texas to 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; and

• a 70% interest in 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:

• five refined product terminals (one of which is 50% owned), located in El Paso, Texas; Moriarty, Bloomfield and Albuquerque, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1.1 million barrels, that are integrated with 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, Texas refinery; and

• 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 near Salt Lake City, Utah, that is permitted to load over 25,000 bpd of light refined products.

Historical Results of Operations

In reviewing the historical results of operations that are discussed below, you should be aware of the following:

The historical financial data prior to our commencement of operations on July 13, 2004 do 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. Also, our historical results of operations prior to July 13, 2004 include revenues and costs associated with crude oil and intermediate product pipelines, which were not contributed to our partnership at its inception.

For periods after commencement of operations by HEP on July 13, 2004, our financial statements reflect:

• net proceeds from our initial public offering which closed on July 13, 2004 (see “Liquidity and Capital Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7);

• the transfer of certain of our predecessor’s operations to HEP, which

– includes our predecessor’s refined product pipeline and terminal assets and short-term debt due to Holly (which was repaid upon the closing of our initial public offering), and

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– excludes our predecessor’s intermediate product pipelines prior to our purchase of those pipelines in July 2005, crude oil systems, accounts receivable from or payable to affiliates, and other miscellaneous assets and liabilities;

• the execution of the Holly PTA and the recognition of revenues derived therefrom for serving Holly’s refineries in New Mexico and Utah; and

• the execution of an omnibus agreement with Holly and several of its subsidiaries (the “Omnibus Agreement”) and the recognition of allocated general and administrative expenses in addition to direct general and administrative expense related to our operation as a publicly owned entity.

NPL constitutes HEP’s predecessor. The transfer of ownership of assets from NPL to HEP represented a reorganization of entities under common control and was recorded at NPL’s historical cost. Accordingly, our financial statements include the historical results of operations of NPL prior to the transfer to HEP.

Agreements with Holly

Under the 15-year Holly PTA, Holly pays us fees to transport on our refined product pipelines or throughput in our terminals a volume of refined products that will produce a minimum level of revenue. This minimum revenue commitment will increase 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. Following the July 1, 2006 PPI adjustment, the volume commitments by Holly under the Holly PTA will produce at least $38.5 million of revenue for the twelve months ending June 30, 2007. Holly pays the published tariff rates on the refined product pipelines and contractually agreed upon fees at the terminals. The tariffs adjust annually at a rate equal to the percentage change in the PPI. The terminal fees will adjust annually based upon an index comprised of comparable fees posted by third parties. Holly’s minimum revenue commitment applies only to the initial assets we acquired from Holly and may not be spread among assets we subsequently acquire. If Holly fails to meet its minimum revenue commitment in any quarter, it is required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met.

Furthermore, if new laws or regulations that affect terminals or pipelines generally are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right 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, after we have made efforts to mitigate their effect. We and Holly will negotiate in good faith to agree on the level of the monthly surcharge or increased tariff rate.

Holly’s obligations under this agreement may be proportionately reduced or suspended if Holly shuts down or materially reconfigures one of its refineries. Holly will be required to give at least twelve months’ advance notice of any long-term shutdown or material reconfiguration. Holly’s obligations may also be temporarily suspended or terminated in certain circumstances.

Under the Omnibus Agreement, we pay Holly an annual administrative fee in the amount of $2.0 million for the provision of various general and administrative services for our benefit. The contract provides that this amount may be increased on the third anniversary following our initial public offering by the greater of 5% or the percentage increase in the consumer price index for the applicable year. Our general partner, with the approval and consent of its conflicts committee, also has the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses. Following the initial three-year period under this agreement, our general partner will determine the general and administrative expenses that will be charged to us. The $2.0 million fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury, 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 other employees of HLS 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

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Holly and its affiliates for direct expenses they incur on our behalf. In addition, we incur additional 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, annual and quarterly reports to unitholders, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees. Under the Omnibus Agreement, Holly also agreed to indemnify us in an aggregate amount not to exceed $15.0 million for ten years after the closing of our initial public offering for any environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing prior to the closing date of our initial public offering.

Alon Transaction

On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport and terminal light refined products for Alon’s refinery in Big Spring, Texas.

The total consideration paid for these pipeline and terminal assets was $120.0 million in cash and 937,500 of our Class B subordinated units which, subject to certain conditions, will convert into an equal number of common units on February 28, 2010. We financed the Alon transaction with a portion of the proceeds of our private offering of $150.0 million principal amount of 6.25% senior notes due 2015 (the “Senior Notes”). In connection with the Alon transaction, we entered into the Alon PTA. Under this agreement, 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, 2006 PPI adjustment, the volume commitments by Alon under the Alon PTA will produce at least $20.5 million of revenue for the twelve months ending February 28, 2007. The agreed upon tariffs increase or decrease each year at a rate equal to the percentage change in the PPI, but not below the initial tariffs. 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. We granted Alon a second mortgage on the pipelines and terminals acquired from Alon to secure certain of Alon’s rights under the Alon PTA. Alon has a right of first refusal to purchase the pipelines and terminals if we decide to sell them in the future. 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.

The consideration for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The allocation of the consideration is based on an independent appraisal. The aggregate consideration amounted to $146.7 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120.0 million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million, representing the allocated value of the 15-year Alon PTA. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

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Holly Intermediate Pipelines Transaction

On July 6, 2005, we entered into a definitive purchase agreement (the “Purchase Agreement”) with Holly to acquire Holly’s Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. On July 8, 2005, we closed on the acquisition for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. We financed the cash portion of the consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of 1,100,000 of our common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal amount of our 6.25% senior notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines granted by Holly to us at the time of our initial public offering in July 2004.

In connection with this transaction, we entered into the Holly IPA, which expires in 2020. Under this agreement, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that would result in initial minimum funds to us of $11.8 million each year that will change annually based on changes in the PPI but will not decrease as a result of a decrease in the PPI. Following the July 1, 2006 PPI adjustment, the volume commitments by Holly under the Holly IPA will result in minimum funds to us of $12.4 million annually. Holly’s minimum revenue commitment applies only to the Intermediate Pipelines, and Holly is not able to spread its minimum revenue commitment among pipeline assets HEP already owns or subsequently acquires. If Holly fails to meet its minimum revenue commitment in any quarter, it is required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met. The Holly IPA may be extended by the mutual agreement of the parties.

We agreed to expend up to $3.5 million to expand the capacity of the Intermediate Pipelines to meet the needs of Holly’s expansion of their Navajo Refinery. As of December 31, 2006, this expansion project was complete and no further expenditures are expected under this obligation. If new laws or regulations are enacted that require us to make substantial and unanticipated capital expenditures with regard to the Intermediate Pipelines, we have the right to amend the tariff rates to recover our costs of complying with these new laws or regulations (including a reasonable rate of return). Under certain circumstances, either party may temporarily suspend its obligations under the Holly IPA. We granted Holly a second mortgage on the Intermediate Pipelines to secure certain of Holly’s rights under the Holly IPA. Holly agreed to provide $2.5 million of additional indemnification above the initial $15.0 million of indemnification under the Omnibus Agreement that previously provided for environmental noncompliance and remediation liabilities occurring or existing before the closing date of the Purchase Agreement, bringing the total indemnification, expiring in 2020, provided to us from Holly to $17.5 million. Of this total, indemnification above $15.0 million relates solely to the Intermediate Pipelines.

As this transaction was among entities under common control, we recorded the acquired assets at Holly’s historic book value of $6.8 million. The $71.9 million excess of the purchase price over the historic book value is recorded as a reduction to partners’ equity for financial accounting purposes.

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

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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 for a particular capital project may be expended over a period of years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years.

In February 2007, the HLS board of directors authorized a letter of intent with Plains All American Pipeline, L.P. (“Plains”) for HEP to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system, now being constructed by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. The pipeline would be owned by a new joint venture company which would be owned 75% by Plains and 25% by HEP. Subject to the actual construction cost, HEP would purchase its interest for between $22.0 and $25.5 million in the first quarter of 2008, when the new pipeline system is expected to become fully operational. The pipeline is being built to 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, which is currently flowing on Plains’ Rocky Mountain Pipeline. Our investment in the project is subject to various conditions, including the negotiation and execution of mutually satisfactory definitive agreements. This investment is expected to take the place of a project that we had been considering to construct and operate a new pipeline called the Porcupine Ridge Pipeline to transport crude oil from the Utah terminus of the Frontier Pipeline to Salt Lake City.

We anticipate that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for smaller capital development projects (including the investment in the Utah crude oil pipeline project as described in the preceding paragraph) will be funded with existing cash balances, cash generated by operations and advances under our four-year $100 million senior secured revolving credit agreement (the “Credit Agreement”).

The HLS board of directors is also considering a project to construct a 12-inch pipeline from Salt Lake City to Las Vegas, with service also to the Cedar City, Utah area. The initial capacity of the pipeline would be approximately 62,000 bpd, and it is expected that the capacity could be later increased up to approximately 118,000 bpd by adding pump stations. The cost of the pipeline is expected to be approximately $235 million, and the total cost of the project including terminals is expected to be approximately $300 million. We are currently in the process of soliciting potential shippers for binding commitments through an “open season” extending to the latter part of March 2007, and we expect to make a final decision on whether to proceed with this project based on the level of commitment from shippers. Certain preliminary work has already been carried out on this project by Holly, but as of the date of this report we have not expended HEP funds or committed to do so with respect to the project. If we choose to carry out this project, our financing for the project would include reimbursement to Holly for previous expenditures and assumption of any commitments previously made by Holly with respect to the project, and might also involve an investment in the project by one or more other companies, making our investment proportionately less.

We expect to use the issuance of common units and/or debt securities as the principal means of financing large investments in major capital projects such as the proposed Salt Lake City to Las Vegas pipeline project described in the preceding paragraph.

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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.

We started our smart pigging program in 1988, prior to Department of Transportation (“DOT”) regulations requiring the program. Beginning in 2002, the DOT required smart pigging or other integrity testing of all DOT-regulated crude oil and refined product pipelines. This requirement is being phased in over a five-year period. As of December 31, 2006 we were in compliance with DOT 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 Refinery and our contractual relationship with Holly under the Omnibus Agreement and the two Holly pipelines and terminals agreements, we believe that we will not face significant competition for barrels of refined products transported from Holly’s Navajo Refinery, particularly during the term of our Holly PTA and Holly IPA expiring in 2019 and 2020, 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.

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We do, however, 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. While 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 acquired from Alon that serve Alon’s Big Springs Refinery. Under the terms of the Holly PTA, we continue to receive a significant portion of the throughput at our terminal facilities from Holly.

Our eleven 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 Federal Energy Regulatory Commission (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 proposed new or changed rates by protest, and challenges to rates that are already on file and in effect by complaint. Upon the appropriate showing, a successful complainant may obtain damages or reparations for generally up to two years prior to the filing of a complaint. The FERC generally has not investigated interstate rates on its own initiative when those rates, like ours, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate any new interstate rates we might file if those rates were protested by a third party and the third party were able to show that it had a substantial economic interest in our tariff rate level. The FERC could also investigate any of our existing interstate rates if a complaint were filed against the rate.

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 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. A state regulatory commission could, however, investigate our rates if such a challenge were filed.

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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. While 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.

Holly agreed to indemnify us in an aggregate amount not to exceed $15.0 million for ten years after the closing of our initial public offering on July 13, 2004 for environmental noncompliance and remediation liabilities associated with the assets initially transferred to us and occurring or existing before that date. When the Intermediate Pipelines were purchased in July 2005, Holly agreed to provide $2.5 million of additional indemnification, bringing the total indemnification provided to us from Holly to $17.5 million. Of this total, indemnification above $15.0 million relates solely to the Intermediate Pipelines. Additionally, we entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon, 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 such releases would be covered under environmental indemnification agreements.

An environmental remediation project is in progress currently at our El Paso terminal, the remaining costs of which are projected to be approximately $1.2 million over the next five years. Other parties are undertaking remediation projects at our Boise, Burley and Albuquerque terminals, and we are obligated to pay a portion of these costs at the Albuquerque terminal, but not at the Boise or Burley terminals. As of December 31, 2006, we estimate the total remaining remediation cost for the Albuquerque terminal to be insignificant. A remediation project is also under way in New Mexico concerning a leak on our refined product pipeline from Artesia, New Mexico to Orla, Texas. At December 31, 2006, we estimate the remaining cost on this project to be $0.2 million, half of which will be incurred in 2007. Holly has agreed, subject to a $15.0 million limit, to indemnify us for environmental liabilities related to the assets transferred to us by Holly to the extent such liabilities existed or arose from operation of these assets prior to the closing of our initial public offering on July 13, 2004 and are asserted within 10 years after that date. The Holly indemnification will cover the costs associated with the three remediation projects mentioned above, including assessment, monitoring, and remediation programs.

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In the fourth quarter of 2005, we experienced a refined product release in Jones County, Texas on one of the pipelines recently acquired from Alon. As of December 31, 2006, we estimate that the total remaining remediation cost for this incident to be insignificant. We also experienced a refined product release near Sweetwater, Texas for which we expect to incur remediation costs of $0.1 million in 2007. Neither of these occurrences is subject to indemnification from Alon.

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 89 people who provide direct support to our operations. None of these employees is covered by collective bargaining agreements. 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 Holly 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 or results of operations could be materially and adversely affected.

We depend upon Holly and particularly its Navajo Refinery for a majority of our revenues; and if those revenues were 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, 2006, Holly accounted for 57% of the revenues of our petroleum products pipelines and 69% 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 and Holly IPA or is unable to meet its minimum revenue commitment for any reason, including due to prolonged downtime or a shutdown at the Navajo Refinery or the Woods Cross Refinery, our revenues 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, 2006, production from the Navajo Refinery accounted for 53% of the throughput volumes transported by our refined product 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 aforce majeurethat 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; and if those revenues were significantly reduced, there would be a material adverse effect on our results of operations.

For the year ended December 31, 2006, Alon accounted for 28% of the combined revenues of our petroleum products pipelines and of our terminals and truck loading racks, including revenues we received from Alon under a capacity lease agreement.

A 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 would depend 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 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 aforce majeureevent occurs beyond the control of either of us, we or Alon could

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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 the only shipper on the Rio Grande Pipeline, a joint venture in which we own a 70% interest and from which we derived 9% of our revenues for the year ended December 31, 2006.

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 common carrier pipeline that is capable of delivering 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. Since inception of Longhorn Pipeline operations in late 2005, little impact has been seen on the operations of Holly, Alon, or HEP. However, if the Longhorn Pipeline is ever able to operate as has been proposed and significantly increases the volumes of refined products it transports, it could result in downward pressure on wholesale refined product prices and refined product margins in El Paso and related markets. Additionally, an increased supply of refined 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, which are currently capacity constrained, could cause a decline in the demand for refined product from Holly or Alon. For Holly, this eventuality could ultimately result in a reduction in Holly’s minimum revenue commitment to us under the Holly PTA and Holly IPA; and while our pipelines and terminals agreement with Alon does not provide for a reduction in Alon’s minimum volume commitment obligation in these circumstances, such eventuality could reduce our opportunity to earn revenue from Alon in excess of Alon’s minimum volume commitment obligation.

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. If refined products become available on the West Coast in excess of demand in that market, additional products could be shipped into our shippers’ Arizona markets with resulting possible 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, 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, lack of drilling activity, natural production 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.

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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 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.

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 ranging from one and one-half to three and one-half years. BP’s agreement to ship on the Rio Grande Pipeline expires in July 2007 and will continue year-to-year thereafter unless cancelled by either party. Our pipelines and terminals agreements with Holly and Alon expire in 2019 and 2020.

Our operations are subject to federal, state, and local laws and regulations relating to 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. 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.

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. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased, and could escalate further. 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 in 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

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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.

Our growth strategy is dependent upon:

• the accuracy of our assumption that many of the markets that we 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, 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 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 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

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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, 18 CRF 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, 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. In 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 would result in lower revenues and cash flows.

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.

If the FERC’s petroleum pipeline rate-making methodology changes, the new methodology could result in tariffs that generate lower revenues and cash flow.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

Changes in the insurance markets attributable to terrorist attacks may 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.

As of December 31, 2006, the principal amount of our total outstanding long-term debt was $185.0 million. 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

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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 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 agreement with Alon restricts us from selling the pipelines and terminals acquired from Alon and from prepaying more than $30.0 million of the Senior Notes until 2015, 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 acquisition, 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.

Our growth through acquisitions may be limited by future market considerations.

Future business or asset acquisitions may be dependent upon financial market conditions. Increases in our average cost of capital resulting from increases in interest rates or changes in our bond rating or from increased cost of equity capital may prevent us from making accretive acquisitions and thus limit our growth opportunities.

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, Oklahoma, Arizona, Colorado, Utah 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 pipelines are regularly inspected and are well maintained, and we believe they are in good repair. Generally, other than as provided in the pipelines and terminal agreements with Holly and Alon, 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.

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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.

	Years Ended December 31,
	2006		2005(1)		2004		2003		2002
Refined products transported for (bpd):
Holly		126,929		94,473		65,525		51,456		55,288
Third parties(2)		62,655		65,053		29,967		23,469		13,553
Total		189,584		159,526		95,492		74,925		68,841
Total annual barrels in thousands (“mbbls”)		69,198		58,227		34,950		27,348		25,127

(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 Rio Grande Pipeline volumes beginning June 30, 2003, when we increased our ownership from 25% to 70% and began consolidating the results of Rio Grande Pipeline.

The following table sets forth certain operating data for each of our petroleum product pipelines. Except as shown below, we own 100% of our refined product 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 20,000 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
	Diameter		Length		Capacity
Origin and Destination	(inches)		(miles)		(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(4)		6/8		105		20,000
Big Spring, TX to Wichita Falls, TX(4)		6/8		227		23,000
Wichita Falls, TX to Duncan, OK(4)		6		47		21,000
Midland, TX to Orla, TX(4)		8/10		135		25,000
Intermediate Product Pipelines:
Lovington, NM to Artesia, NM(5)		8		65		48,000
Lovington, NM to Artesia, NM(5)		10		65		72,000
Rio Grande Pipeline Company:
Rio Grande Pipeline(6)		8		249		27,000

(1)	Includes 20,000 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 our Moriarty to Bloomfield pipeline is leased from Mid-America Pipeline Company, LLC under a long-term lease agreement.
(3)	Capacity for this pipeline is reflected in the information for the Artesia to Moriarty pipeline.
(4)	Acquired from Alon on February 28, 2005.
(5)	Acquired from Holly on July 8, 2005.
(6)	We have a 70% joint venture interest in the entity that owns this pipeline. Capacity reflects a 100% interest. We increased our ownership interest in Rio Grande Pipeline Company from 25% to 70% on June 30, 2003.

For the years ended December 31, 2006 and 2005, Holly shipped an aggregate of 52.6% and 50.4%, respectively, of the petroleum products transported on our refined product pipelines and 100% of the petroleum products transported on our Intermediate Pipelines. For the same periods, these pipelines transported approximately 95% of the light refined products produced by Holly’s Navajo Refinery.

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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 truck rack for local delivery by tanker truck. Holly is the only shipper on this pipeline. The refined products shipped on this pipeline represented 20% of the total light refined products produced at Holly’s Navajo Refinery during 2006. 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, 67-mile and a 12-inch, 14-mile segment from the Navajo Refinery to Orla, Texas, constructed in 1981;

• a 12-inch, 99-mile segment from Orla to outside El Paso, Texas, constructed in 1996; and

• an 8-inch, 35-mile segment from outside El Paso to our El Paso terminal, constructed in the mid 1950’s

There are two shippers on this pipeline, Holly and Alon. In 2006, this pipeline transported to our El Paso terminal 49% 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, the pipeline received volumes of gasoline and diesel from Alon’s Big Spring, Texas refinery through a tie-in to an Alon pipeline system.

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 our 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 Pipeline Company, LLC (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 $487,000 to Mid-America Pipeline Company, LLC 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 Pipeline Company, LLC. 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 Pipeline Company, LLC (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, Texas to our tank farm at Orla, Texas. Alon is the only shipper on this pipeline.

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 and crude oil from Holly’s Lovington, New Mexico facility to Holly’s Artesia, New Mexico facility. Holly is the only shipper on this pipeline.

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, New Mexico facility to Holly’s Artesia, New Mexico facility. Holly is the only shipper on this pipeline.

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.

Rio Grande was formed in 1996, at which time we contributed nearly 220 miles of pipeline from near Odessa, Texas to outside El Paso, Texas in exchange for a 25% interest in the joint venture. Rio Grande Pipeline began operations in 1997. In June 2003, we acquired an additional 45% interest in the joint venture from Juarez Pipeline Co., an affiliate of The Williams Companies, Inc., for $28.7 million. The pipeline has recently completed a reconditioning project that could facilitate an expansion to 32,000 bpd. Currently, only LPG’s are transported on this pipeline, and BP is the only shipper. BP’s contract provides that BP will ship a minimum average of 16,500 bpd for the duration of the agreement. This contract expires in July 2007, but will continue year-to-year thereafter unless cancelled by either party at the beginning of a contract year in which the contract was not cancelled. 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. We paid $745,000 to the then-current operator as an inducement to and consideration for its early resignation. As operator, we receive a management fee of $1.1 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.

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REFINED PRODUCT TERMINALS AND TRUCK RACKS

Our refined product terminals receive products from pipelines, 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.

The table below sets forth the total average throughput for our refined product terminals in each of the periods presented:

	Years Ended December 31,
	2006		2005(1)		2004		2003		2002
Refined products terminalled for (bpd):
Holly		118,202		120,795		114,991		86,780		81,969
Third parties		43,285		42,334		24,821		19,956		12,374
Total		161,487		163,129		139,812		106,736		94,343
Total annual barrels in thousands (mbbls)		58,943		59,542		51,171		38,959		34,435

(1) Includes volumes for the terminals and tank farm acquired from Alon February 28, 2005.

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The following table outlines the locations of our terminals and their storage capacities, number of tanks, supply source, and mode of delivery:

	Storage		Number
	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
Albuquerque, NM		64,000	9	Pipeline	Truck
Tucson, AZ(1)		176,000	9	Pipeline	Truck
Mountain Home, ID(2)		120,000	3	Pipeline	Pipeline
Boise, ID(3) (4)		111,000	9	Pipeline	Pipeline
Burley, ID(3)		70,000	7	Pipeline	Truck
Spokane, WA		333,000	32	Pipeline/Rail	Truck
Abilene, TX(5)		127,000	5	Pipeline	Truck/Pipeline
Wichita Falls, TX(5)		220,000	11	Pipeline	Truck/Pipeline
Orla tank farm(5)		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		2,245,000

(1)	The Tucson terminal consists of two parcels. On one parcel, we lease the underlying ground as a 50% co-tenant with a division of Valero, L.P. (“Valero”) pursuant to which we own 50% of the improvements on that parcel. On the other parcel, our joint venture with Valero leases the underlying ground and owns the improvements. This joint venture agreement gives us rights to 100% of the terminal capacity (for both parcels), which is operated by Valero for a fee.
(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.
(4)	This terminal has seen limited use since its acquisition in June 2003.
(5)	Acquired from Alon on February 28, 2005.

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 83% of the volumes at this terminal. We also receive product from Alon’s Big Spring, Texas refinery that accounted for 17% of the volumes at this terminal in 2006. Refined products received at this terminal are sold locally via the truck rack, transported to our Tucson terminal on Kinder Morgan Energy Partners L.P.’s East System pipeline or to our Albuquerque terminal on the Juarez pipeline, which was acquired from Chevron by Plains Pipeline, L.P. in September 2006 (the “Plains Pipeline”). Competition in this market includes a refinery and terminal owned by Western Refining, a joint venture pipeline and terminal owned by ConocoPhillips and Valero, L.P. 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 terminal owned by Giant Industries.

Albuquerque Terminal
We receive light refined products from Holly that are transported on the Plains Pipeline from our El Paso terminal and account for over 90% of the volumes at this terminal. We also receive product from ConocoPhillips and Valero, L.P. that are transported to the Albuquerque terminal on Valero, L.P.’s West Emerald pipeline from its McKee, Texas refinery. Refined products received at this terminal are sold locally, via the truck rack. Competition in the Albuquerque market includes terminals owned by Chevron,

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ConocoPhillips, Giant and Valero. We and ConocoPhillips each owned a 50% interest in the Albuquerque terminal through July 2004, at which time we acquired the 50% interest owned by ConocoPhillips.

Tucson Terminal
The Tucson terminal consists of two parcels. On one parcel, we lease the underlying ground as a 50% co-tenant with a division of Valero pursuant to which we own 50% of the improvements on that parcel. On the other parcel, our joint venture with Valero leases the underlying ground and owns the improvements. This joint venture agreement gives us rights to 100% of the terminal capacity (for both parcels), which is operated by Valero for a fee. We receive light refined products at this terminal 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 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’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. Shell and Chevron are the 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 2006. 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 2006. Refined products received at this terminal are sold via a truck rack or shipped to Alon’s terminal in Duncan, Oklahoma. Alon is the only customer at this terminal.

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 2006. 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.

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 modern, 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 2006.

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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 began trading on the New York Stock Exchange under the symbol “HEP” commencing with our initial public offering on July 8, 2004. 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
2006
Fourth Quarter	$	41.10	$	37.90	$	0.665		876,800
Third Quarter	$	40.44	$	35.80	$	0.655		957,700
Second Quarter	$	42.58	$	38.15	$	0.640		704,100
First Quarter	$	42.75	$	37.00	$	0.625		1,165,000
2005
Fourth Quarter	$	44.14	$	35.80	$	0.600		1,014,800
Third Quarter	$	45.40	$	39.10	$	0.575		1,068,700
Second Quarter	$	47.00	$	37.28	$	0.550		1,375,300
First Quarter	$	40.45	$	32.25	$	0.500		1,825,100

A distribution for the quarter ended December 31, 2006 of $0.675 per unit was paid on February 14, 2007.

As of February 9, 2007, we had approximately 4,200 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 Senior Notes will prohibit 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 will 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 will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and

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subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in our partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009.

The Class B subordinated units issued to Alon generally vote as a single class and rank equally with our existing subordinated units. There will be 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	%

In the fourth quarter of 2006, we paid $0.1 million for the purchase of 3,210 of our common units in the open market for the recipients of all 2006 restricted unit grants.

							Maximum Number
					Total Number of		of Units that May
					Units Purchased		Yet Be Purchased
	Total Number of				as Part of Publicly		Under a Publicly
	Units		Average Price		Announced Plan		Announced Plan
Period	Purchased		Paid Per Unit		or Program		or Program
October 2006		—	$	—		—		—
November 2006		—	$	—		—		—
December 2006		3,210	$	38.14		—		—
Total		3,210				—

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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.

							2004
							Combined			Successor			Predecessor
										July 13, 2004			January 1,
	Year Ended			Year Ended			Year Ended			Through			2004 Through			Year Ended			Year Ended
	December 31,			December 31,			December 31,			December 31,			July 12,			December 31,			December 31,
	2006			2005			2004(1)			2004			2004			2003			2002
							(In thousands, except per unit data)
Statement Of Income Data:
Revenue	$	89,194		$	80,120		$	67,766		$	28,182		$	39,584		$	30,800		$	23,581
Operating costs and expenses
Operations		28,630			25,332			23,641			10,104			13,537			24,193			19,442
Depreciation and amortization		15,330			14,201			7,224			3,241			3,983			6,453			4,475
General and administrative		4,854			4,047			1,860			1,859			1			—			—
Total operating costs and expenses		48,814			43,580			32,725			15,204			17,521			30,646			23,917
Operating income (loss)		40,380			36,540			35,041			12,978			22,063			154			(336	)
Interest income		899			649			144			65			79			291			269
Interest expense		(13,056	)		(9,633	)		(697	)		(697	)		—			—			—
Equity in earnings of Rio Grande Pipeline Company		—			—			—			—			—			894			2,737
		(12,157	)		(8,984	)		(553	)		(632	)		79			1,185			3,006
Income before minority interest		28,223			27,556			34,488			12,346			22,142			1,339			2,670
Minority interest in Rio Grande Pipeline Company		(680	)		(740	)		(1,994	)		(956	)		(1,038	)		(758	)		—
Net income		27,543			26,816			32,494			11,390			21,104			581			2,670
Less:
Net income attributable to Predecessor		—			—			21,104			—			21,104			581			2,670
General partner interest in net income		1,710			721			228			228			—			—			—
Limited partners’ interest in net income	$	25,833		$	26,095		$	11,162		$	11,162		$	—		$	—		$	—
Net income per limited partner unit – basic and diluted	$	1.60		$	1.70					$	0.80
Cash distributions declared per unit applicable to limited partners	$	2.585		$	2.225					$	0.435
Other Financial Data:
EBITDA(2)	$	55,030		$	50,001		$	40,271		$	15,263		$	25,008		$	6,743		$	6,876
Cash flows from operating activities	$	45,853		$	42,628		$	15,867		$	15,371		$	496		$	5,909		$	4,271
Cash flows from investing activities	$	(9,107	)	$	(131,795	)	$	(2,977	)	$	(305	)	$	(2,672	)	$	(27,947	)	$	(4,271	)
Cash flows from financing activities	$	(45,774	)	$	90,646		$	(480	)	$	1,770		$	(2,250	)	$	28,372		$	—
Maintenance capital expenditures(3)	$	1,095		$	364		$	1,197		$	305		$	892		$	1,934		$	1,178
Expansion capital expenditures		8,012			3,519			1,780			—			1,780			4,837			5,580
Total capital expenditures	$	9,107		$	3,883		$	2,977		$	305		$	2,672		$	6,771		$	6,758
Balance Sheet Data (at period end):
Net property, plant and equipment	$	160,484		$	162,298		$	74,626		$	74,626		$	95,337		$	95,826		$	60,073
Total assets	$	243,573		$	254,775		$	103,758		$	103,758		$	156,373		$	140,425		$	88,338
Long-term debt	$	180,660		$	180,737		$	25,000		$	25,000		$	—		$	—		$	—
Total liabilities	$	196,384		$	190,962		$	28,998		$	28,998		$	53,146		$	57,089		$	20,059
Net partners’ equity(4)	$	36,226		$	52,060		$	61,528		$	61,528		$	89,964		$	68,860		$	68,279

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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 the investor with additional information for comparing year-over-year information.

(2)

Earnings before interest, taxes, depreciation and amortization (“EBITDA”) are calculated as net income plus (a) interest expense net of interest income and (b) depreciation and amortization. EBITDA is a non-GAAP measure. 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 enhances an investor’s understanding of our ability to satisfy principal and interest obligations with respect to our indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. See “Historical Results of Operations” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for certain changes made effective January 1, 2004 in how we recorded transactions, which would affect the comparability of EBITDA for periods after January 1, 2004 with EBITDA for the prior years.

							2004
							Combined			Successor			Predecessor
										July 13,			January 1,
	Year			Year			Year			2004			2004			Year			Year
	Ended			Ended			Ended			Through			Through			Ended			Ended
Reconciliation of EBITDA to	December			December			December			December			July			December			December
net income	31, 2006			31, 2005			31, 2004			31, 2004			12,2004			31,2003			31,2002
	(In thousands)
Net income	$	27,543		$	26,816		$	32,494		$	11,390		$	21,104		$	581		$	2,670
Add depreciation and amortization		15,330			14,201			7,224			3,241			3,983			6,453			4,475
Add interest expense		13,056			9,633			697			697			—			—			—
Subtract interest income		(899	)		(649	)		(144	)		(65	)		(79	)		(291	)		(269	)
EBITDA	$	55,030		$	50,001		$	40,271		$	15,263		$	25,008		$	6,743		$	6,876

(3)	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.
(4)	As a master limited partnership, we distribute our available cash, which exceeds 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.

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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 formed by Holly and is the successor to NPL. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande. On July 7, 2004, we priced 6,100,000 common units for the initial public offering and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $145.5 million, net of $10.3 million of underwriting commissions. All the initial assets of HEP were contributed by Holly and its subsidiaries in exchange for (a) 7,000,000 subordinated units, representing 49% limited partner interest in HEP, (b) incentive distribution rights, (c) the 2% general partner interest and d) an aggregate cash distribution of $125.6 million.

We operate a system of petroleum product pipelines in Texas, New Mexico and Oklahoma, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington. We generate revenues by charging tariffs for transporting petroleum products 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.

On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas that serve Alon’s Big Spring, Texas refinery. Please read “Alon Transaction” under “Liquidity and Capital Resources” below for additional information.

On July 8, 2005, we acquired Holly’s Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. Please read “Holly Intermediate Pipelines Transaction” under “Liquidity and Capital Resources” below for additional information.

As a result of the Alon transaction, Holly’s ownership interest was reduced from 51% to 47.9%, including the 2% general partner interest. Holly’s ownership was further reduced to 45.0% in July 2005 following the Intermediate Pipelines transaction.

Historical Results of Operations

In reviewing the historical results of operations that are discussed below, you should be aware of the following:

Until January 1, 2004, our historical revenues included only actual amounts received from:

• third parties who utilized our pipelines and terminals;

• Holly for use of our FERC-regulated refined product pipeline; and

• Holly for use of the Lovington crude oil pipelines, which were not contributed to our partnership.

Until January 1, 2004, we did not record revenue for:

• transporting products for Holly on our intrastate refined product pipelines;

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• providing terminalling services to Holly; and

• transporting crude oil and feedstocks on the Intermediate Pipelines that connect Holly’s Artesia and Lovington facilities, which were not contributed to our partnership.

Commencing January 1, 2004, we began charging Holly fees for the use of all of our pipelines and terminals at the rates set forth in the Holly PTA described below under “Agreements with Holly”.

Furthermore, the historical financial data do not reflect any general and administrative expenses prior to July 13, 2004 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.

For periods after commencement of operations by HEP on July 13, 2004, our financial statements reflect:

• net proceeds from our initial public offering which closed on July 13, 2004 (see “Liquidity and Capital Resources” below);

• the transfer of certain of our predecessor’s operations to HEP, which

– includes our predecessor’s refined product pipeline and terminal assets and short-term debt due to Holly (which was repaid upon the closing of our initial public offering), and

– excludes our predecessor’s crude oil systems, intermediate product pipelines, accounts receivable from or payable to affiliates, and other miscellaneous assets and liabilities;

• the execution of the Holly PTA and the recognition of revenues derived therefrom; and

• the execution of the Omnibus Agreement with Holly and several of its subsidiaries and the recognition of allocated general and administrative expenses in addition to direct general and administrative expense related to our operation as a publicly owned entity.

NPL constitutes HEP’s predecessor. The transfer of ownership of assets from NPL to HEP represented a reorganization of entities under common control and was recorded at NPL’s historical cost. Accordingly, our financial statements include the historical results of operations of NPL prior to the transfer to HEP.

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Agreements with Holly

Under the 15-year Holly PTA, Holly pays us fees to transport on our refined product pipelines or throughput in our terminals a volume of refined products that will produce a minimum level of revenue. Following the July 1, 2006 PPI adjustment, the volume commitments by Holly under the Holly PTA will produce at least $38.5 million of revenue annually.

Prior to July 13, 2004, Holly did not allocate any of its general and administrative expenses to its pipeline and terminalling operations. Under the Omnibus Agreement, we pay Holly an annual administrative fee in the amount of $2.0 million for the provision by Holly or its affiliates of various general and administrative services to us. This fee does not include the salaries of pipeline and terminal personnel or other employees of HLS 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 connection with our acquisition of the Intermediate Pipelines, we entered into the 15-year Holly IPA. Under this agreement, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that will produce a minimum level of funds to us. Following the July 1, 2006 PPI adjustment, the volume commitments by Holly under the Holly IPA will result in minimum funds to us of $12.4 million annually.

Please read “Agreements with Holly” under Item 1, “Business” for additional information on these agreements with Holly.

RESULTS OF OPERATIONS

The following tables present our operating income, volume information, and cash flow summary information for the years ended December 31, 2006, 2005 and 2004. Prior to January 1, 2004, we recorded pipeline tariff revenues only on FERC-regulated pipelines and terminal service fee revenues from third-party customers. No revenues from affiliates were recorded on non-FERC regulated pipelines and no terminal services fee revenues from affiliates were recorded for use of our terminal facilities. Commencing January 1, 2004, affiliate revenues have been recorded for all pipeline and terminal facilities included in our pipeline and terminal facilities. Additionally, the 2004 information is split for the period prior to our initial public offering, captioned “Predecessor” and for the period following our initial public offering, captioned “Successor”. The information for the 2004 Predecessor and Successor periods are added together and presented under the caption “Combined.” As a result, the information included in the following table of operating income is not fully comparable on a year-over-year basis.

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							2004
							Combined			Successor			Predecessor
										July 13, 2004
	Year Ended			Year Ended			Year Ended			through			January 1,
	December 31,			December 31,			December 31,			December 31,			2004 through
	2006			2005			2004(1)			2004			July 12, 2004
				(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	31,723		$	29,288		$	28,533		$	13,498		$	15,035
Affiliates – intermediate pipelines		10,733			4,643			—			—			—
Third parties		31,685			31,447			18,952			8,915			10,037
		74,141			65,378			47,485			22,413			25,072
Terminals and truck loading racks:
Affiliates		10,422			10,253			9,194			4,419			4,775
Third parties		4,631			4,489			3,179			1,349			1,830
		15,053			14,742			12,373			5,768			6,605
Other		—			—			15			1			14
Total for pipelines and terminal assets		89,194			80,120			59,873			28,182			31,691
Crude system and intermediate pipelines not contributed to HEP at inception(2):
Lovington crude oil pipelines		—			—			3,325			—			3,325
Intermediate pipelines		—			—			4,568			—			4,568
Total for crude system and intermediate pipeline assets not contributed to HEP at inception		—			—			7,893			—			7,893
Total revenues		89,194			80,120			67,766			28,182			39,584
Operating costs and expenses
Costs related to pipeline and refined product terminal assets acquired by successor:
Operations		28,630			25,332			21,361			10,104			11,257
Depreciation and amortization		15,330			14,201			6,791			3,241			3,550
General and administrative		4,854			4,047			1,860			1,859			1
		48,814			43,580			30,012			15,204			14,808
Crude system and intermediate pipelines not contributed to HEP at inception(2):
Operations		—			—			2,280			—			2,280
Depreciation and amortization		—			—			433			—			433
		—			—			2,713			—			2,713
Total operating costs and expenses		48,814			43,580			32,725			15,204			17,521
Operating income		40,380			36,540			35,041			12,978			22,063
Interest income		899			649			144			65			79
Interest expense, including amortization		(13,056	)		(9,633	)		(697	)		(697	)		—
Minority interest in Rio Grande Pipeline Company		(680	)		(740	)		(1,994	)		(956	)		(1,038	)
Net income		27,543			26,816			32,494			11,390			21,104
Less:
Net income applicable to Predecessor		—			—			21,104			—			21,104
General partner interest in net income, including incentive distributions(3)		1,710			721			228			228			—
Limited partners’ interest in net income	$	25,833		$	26,095		$	11,162		$	11,162		$	—
Net income per limited partner unit — basic and diluted(3)	$	1.60		$	1.70					$	0.80
Weighted average limited partners’ units outstanding		16,108			15,356						14,000
EBITDA(4)	$	55,030		$	50,001		$	40,271		$	15,263		$	25,008
Distributable cash flow(5)	$	47,219		$	41,438					$	14,492

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					2004
					Combined		Successor		Predecessor
							July 13, 2004
	Year Ended		Year Ended		Year Ended		through		January 1,
	December 31,		December 31,		December 31,		December 31,		2004 through
	2006		2005		2004		2004		July 12, 2004
Volumes (bpd)(6)
Pipelines:
Affiliates – refined product pipelines		69,271		66,206		65,525		66,017		65,089
Affiliates – intermediate pipelines		57,658		28,267		—		—		—
Third parties		62,655		65,053		29,967		30,310		29,663
		189,584		159,526		95,492		96,327		94,752
Terminals and truck loading racks:
Affiliates		118,202		120,795		114,991		114,690		115,259
Third parties		43,285		42,334		24,821		22,922		26,505
		161,487		163,129		139,812		137,612		141,764
Total for pipelines and terminal assets (bpd)		351,071		322,655		235,304		233,939		236,516

(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 the investor with additional information for comparing year-over-year information.

(2) Revenue and expense items generated by the crude system and Intermediate Pipeline assets that were not contributed to HEP at inception in July 2004. Historically, these items were included in the income of NPL as predecessor, but are not included in the income of HEP beginning July 13, 2004. The Intermediate Pipelines were later purchased by HEP on July 8, 2005.

(3) 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 limited partners’ interest in net income is divided by the weighted average limited partner units outstanding in computing the net income per unit applicable to limited partners.

(4) Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income plus (a) interest expense net of interest income and (b) depreciation and amortization. EBITDA is a non-GAAP measure. 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
	Year Ended			Year Ended			Year Ended			through			January 1,
	December 31,			December 31,			December 31,			December 31,			2004 through
	2006			2005			2004			2004			July 12, 2004
							(In thousands)
Net income	$	27,543		$	26,816		$	32,494		$	11,390		$	21,104
Add interest expense		12,088			8,848			531			531			—
Add amortization of discount and deferred debt issuance costs		968			785			166			166			—
Subtract interest income		(899	)		(649	)		(144	)		(65	)		(79	)
Add depreciation and amortization		15,330			14,201			7,224			3,241			3,983
EBITDA	$	55,030		$	50,001		$	40,271		$	15,263		$	25,008

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(5) Distributable cash flow is not a calculation based upon U.S. 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.

Set forth below is our calculation of distributable cash flow attributable to partners subsequent to the formation on July 13, 2004.

	Successor
							July 13, 2004
	Year Ended			Year Ended			through
	December 31,			December 31,			December 31,
	2006			2005			2004
				(In thousands)
Net income	$	27,543		$	26,816		$	11,390
Add depreciation and amortization		15,330			14,201			3,241
Add amortization of discount and deferred debt issuance costs		968			785			166
Increase in deferred revenue		4,473			—			—
Subtract maintenance capital expenditures*		(1,095	)		(364	)		(305	)
Distributable cash flow	$	47,219		$	41,438		$	14,492

* Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives.

(6) The amounts reported represent volumes from the initial assets contributed to HEP at inception in July 2004 and additional volumes from the assets acquired from Alon starting in March 2005 and the Intermediate Pipelines acquired from Holly starting in July 2005. The amounts reported in the 2005 periods include volumes on the acquired assets subsequent to the respective acquisition dates averaged over the full reported periods.

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Results of Operations – Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

Summary

Net income was $27.5 million for the year ended December 31, 2006, an increase of $0.7 million from $26.8 million for the year ended December 31, 2005. The increase in overall earnings was principally due to the earnings generated from the Intermediate Pipelines acquired from Holly on July 8, 2005, for which we realized earnings for only six months in 2005, and increases in volumes transported by affiliates on our intermediate and refined product pipeline systems following Holly’s completion in June 2006 of an expansion of the Navajo Refinery. Also favorably impacting earnings in 2006 were the effects of the annual tariff increases on our pipelines and the recognition of certain previously deferred revenue. Partially offsetting these positive factors was a reduction of volumes transported and terminalled in the second quarter of 2006 due to significant refinery downtime experienced by all of the refineries utilizing our refined product distribution network (described below) and higher interest expense principally related to the senior notes issued in connection with the pipeline and terminal assets acquired from Alon in early 2005 and the Intermediate Pipelines acquired from Holly in July 2005.

Revenues

Revenues of $89.2 million for the year ended December 31, 2006 were $9.1 million greater than the $80.1 million for the comparable period of 2005. This increase was principally due to an increase in volumes transported on the pipeline and terminal assets acquired from Alon in early 2005 and the Intermediate Pipelines acquired from Holly in July 2005, for which we realized revenues for only ten and six of the twelve months of 2005, respectively. Additionally, favorably impacting revenues for the year ended December 31, 2006 was the recognition of certain previously deferred revenue, an increase in volumes transported by affiliates following the Navajo Refinery expansion, and the effects of the annual tariff increases on our pipelines. Partially offsetting these increases, was a reduction of volumes transported and terminalled in the second quarter of 2006 due to significant refinery downtime experienced by all of the refineries utilizing our refined product distribution network as discussed below. Also impacting revenue for the year ended December 31, 2006, BP completed its obligation to pay the border crossing fee under BP’s Rio Grande Pipeline contract in 2005. We did not have border crossing fee revenues for the year ended December 31, 2006, due to the fulfillment of this contract.

All of the refineries utilizing our refined product distribution network, including Holly’s Navajo and Woods Cross refineries and Alon’s Big Spring refinery, were required to produce ultra low sulfur diesel fuel (“ULSD”) by June 2006. To meet this requirement, significant downtime at the refineries was required during the quarter ended June 30, 2006, so that ULSD-associated projects could be brought on line. Additionally, Holly completed an expansion of the Navajo Refinery, which required additional unit downtime. The tie-in of these new projects coming on line, combined with other refinery maintenance, much of which was timed in conjunction with the capital projects, resulted in reduced refinery production, which was the principal factor contributing to a significant volume decrease during the second quarter of 2006.

Revenues from refined product pipelines increased by $2.7 million from $60.7 million for the year ended December 31, 2005 to $63.4 million for the year ended December 31, 2006. Shipments on our refined product pipelines averaged 131.9 thousand barrels per day (“mbpd”) for the year ended December 31, 2006 as compared to 131.3 mbpd for the year ended December 31, 2005. Refined product pipeline revenues for the year ended December 31, 2006 were negatively impacted due to BP’s completion of its border crossing fee obligations under BP’s Rio Grande Pipeline contract in early 2005. We had no border crossing fee revenues for the year ended December 31, 2006 as compared to $0.8 million in 2005 due to the fulfillment of this contract.

Revenues from the Intermediate Pipelines increased by $6.1 million from $4.6 million for the year ended December 31, 2005 to $10.7 million for the year ended December 31, 2006. This increase includes $1.0

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million attributable to the recognition of previously deferred revenue as the contractual period for us to provide certain pipeline services had expired. Shipments on the Intermediate Pipelines averaged 57.7 mbpd for the year ended December 31, 2006 as compared to 28.3 mbpd for the year ended December 31, 2005. The increase was principally due to realizing revenues for a full twelve months of volumes during the year ended December 31, 2006, while we realized revenues for only six months during the year ended December 31, 2005.

Revenues from terminal and truck loading rack service fees increased by $0.4 million from $14.7 million for the year ended December 31, 2005 to $15.1 million for the year ended December 31, 2006, principally due to rates increases in terminal fees charged to our affiliates. Refined products terminalled in our facilities for the comparable periods decreased to 161.5 mbpd in the year ended December 31, 2006 from 163.1 mbpd in the year ended December 31, 2005.

Operations Expense

Operations expense increased $3.3 million from the year ended December 31, 2005 to the year ended December 31, 2006. This increase in expense was principally due to $2.2 million of increased direct operating costs relating to the assets acquired from Alon and direct operating costs of $0.7 million for the Intermediate Pipelines that were acquired in July 2005. Additionally impacting operations expense were other year-over-year increases in pipeline and terminal maintenance expense and direct operating costs relating to the personnel who support our operations.

Depreciation and Amortization

Depreciation and amortization was $1.1 million higher in the year ended December 31, 2006 than in the year ended December 31, 2005, due principally to the increase in depreciation from the pipeline and terminal assets acquired from Alon in 2005.

General and Administrative

General and administrative costs were $4.9 million for the year ended December 31, 2006, an increase of $0.9 million from $4.0 million for the year ended December 31, 2005 due mainly to equity-based compensation expense and business development costs.

Interest Expense

Interest expense for the year ended December 31, 2006 totaled $13.1 million, an increase of $3.5 million from $9.6 million for the year ended December 31, 2005. The increase is due to the debt issued in connection with the Alon and Intermediate Pipelines acquisitions. In the year ended December 31, 2006, interest expense consisted of: $11.6 million of interest on the outstanding debt, net of the impact of the interest rate swap; $0.5 million of commitment fees on the unused portion of the Credit Agreement; and $1.0 million of amortization of the discount on the Senior Notes and deferred debt issuance costs. In the year ended December 31, 2005, interest expense consisted of: $8.4 million of interest on the outstanding debt, net of the impact of the interest rate swap; $0.4 million of commitment fees on the unused portion of the Credit Agreement; and $0.8 million of amortization of the discount on the Senior Notes and deferred debt issuance costs.

Minority Interest in Earnings of Rio Grande

The minority interest related to the 30% of Rio Grande that we do not own for the year ended December 31, 2006 was comparable to the year ended December 31, 2005. The minority interest in Rio Grande reduced our income by $0.7 million for the years ended December 31, 2006 and 2005.

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Results of Operations – Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

Summary

Net income was $26.8 million for the year ended December 31, 2005, a decrease of $5.7 million from $32.5 million for the year ended December 31, 2004. The decrease in income was principally due to the inclusion in earnings of $5.2 million in the prior year period of the crude oil and Intermediate Pipelines that were not contributed to the Partnership at inception, reduced revenues from Rio Grande, general and administrative charges currently being incurred by the Partnership that were not allocated prior to the initial public offering, and interest expense principally related to the Senior Notes issued in connection with the Alon and Intermediate Pipelines transactions, partially offset by the additional income generated from the assets acquired from Alon and the Intermediate Pipelines subsequently acquired from Holly, and additional revenues from our existing pipelines and terminals.

Revenues

Revenues of $80.1 million for the year ended December 31, 2005 were $12.3 million greater than the $67.8 million in the comparable period of 2004, principally due to $17.6 million of revenues from the pipeline and terminal assets acquired from Alon on February 28, 2005 and $4.6 million of revenues from the Intermediate Pipeline assets acquired from Holly on July 8, 2005, partially offset by revenues of $7.9 million in the year ended December 31, 2004 from assets not originally contributed to the Partnership. Also, we had additional revenues from our existing pipelines and terminals of $1.7 million and reduced revenues from the Rio Grande Pipeline of $3.7 million.

Revenues from refined product pipelines increased by $13.2 million from $47.5 million for the year ended December 31, 2004 to $60.7 million for the year ended December 31, 2005. Shipments on our refined product pipelines averaged 131.3 mbpd for the year ended December 31, 2005 as compared to 95.5 mbpd for the year ended December 31, 2004, principally due to the incremental March to December 2005 volumes from the pipelines acquired from Alon, combined with increased volumes shipped by Holly and its affiliates, partially offset by reduced volumes shipped on the Rio Grande Pipeline.

Revenues from the Intermediate Pipelines purchased from Holly in July 2005 contributed $4.6 million to revenue in the year ended December 31, 2005. Revenues from crude system and Intermediate Pipeline assets not contributed to HEP were $7.9 million for the year ended December 31, 2004, as a result of including operations of the predecessor only until July 13, 2004, the commencement of operations of HEP. As anticipated, during the first quarter of 2005, based on the aggregate volumes shipped by BP on the Rio Grande Pipeline, BP is no longer required to pay the border crossing fee pursuant to its contract. For the years ended December 31, 2005 and 2004, the border crossing fee was $0.8 million and $4.5 million, respectively.

Revenues from terminal and truck loading rack service fees increased by $2.3 million from $12.4 million for the year ended December 31, 2004 to $14.7 million for the year ended December 31, 2005. Refined products terminalled in our facilities for the comparable periods rose to 163.1 mbpd in the year ended December 31, 2005 from 139.8 mbpd in the year ended December 31, 2004, due to the incremental March to December 2005 volumes from the terminals acquired from Alon and volume gains at our existing terminals.

Operations Expense

Operations expense increased $1.7 million from the year ended December 31, 2004 to the year ended December 31, 2005. This increase in expense was principally due to $3.4 million of operating costs relating to the assets acquired from Alon, combined with operating costs of $0.6 million for the Intermediate Pipelines that were acquired in July 2005, partially offset by operating costs of $2.3 million for the crude oil and Intermediate Pipelines that were not contributed to HEP in July 2004.

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Depreciation and Amortization

Depreciation and amortization was $7.0 million higher in the year ended December 31, 2005 than in the year ended December 31, 2004, due principally to the increase in depreciation from the assets acquired from Alon.

General and Administrative

General and administrative costs were $4.0 million for the year ended December 31, 2005, an increase of $2.1 million from $1.9 million for the year ended December 31, 2004. No general and administrative costs were incurred prior to HEP’s formation date of July 13, 2004, as Holly did not allocate any general and administrative costs to its subsidiaries.

Interest Expense

Interest expense for the year ended December 31, 2005 totaled $9.6 million, an increase of $8.9 million from $0.7 million for the year ended December 31, 2004. The increase is due to the debt issued in connection with the Alon and Intermediate Pipelines acquisitions. In the year ended December 31, 2005, interest expense consisted of: $8.4 million of interest on the outstanding debt, net of the impact of the interest rate swap; $0.4 million of commitment fees on the unused portion of the Credit Agreement; and $0.8 million of amortization of the discount on the Senior Notes and deferred debt issuance costs. As no interest expense was incurred prior to formation on July 13, 2004, only $0.7 million of interest expense was recorded on the Credit Agreement and commitment fees for the year ended December 31, 2004.

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 $0.7 million in year ended December 31, 2005 compared to $2.0 million in the year ended December 31, 2004.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100.0 million senior secured revolving credit agreement. During 2005, amendments were made to the Credit Agreement to allow for the closing of the Alon transaction and the related Senior Notes offering, the closing of the Holly Intermediate Pipelines transaction and to amend certain of the restrictive covenants. As of December 31, 2006, we had no amounts outstanding under the Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes.

We financed the $120.0 million cash portion of the consideration for the Alon transaction through our private offering on February 28, 2005 of $150.0 million of 6.25% Senior Notes due 2015. We used the balance to repay $30.0 million of outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes. On July 28, 2005, we filed a registration statement to allow the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the SEC with substantially identical terms, which exchange was completed in October 2005.

We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the private sale of 1,100,000 of our common units to a limited number of institutional investors which closed simultaneously with the closing of the acquisition of the Intermediate Pipelines on July 8, 2005. On September 2, 2005, we filed a registration statement with the SEC using a “shelf” registration process which allows the institutional investors to freely transfer their units.

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Additionally under this shelf process, we may offer from time to time up to $800.0 million 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.

As of December 31, 2006, we have no amounts outstanding under the Credit Agreement, and now have $100.0 million available and unused under our revolving credit facility. 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. In February, May, August and November 2006, we paid regular quarterly cash distributions of $0.625, $0.64, $0.655 and $0.665, respectively, on all units, an aggregate amount of $43.7 million. Included in these distributions was an aggregate of $1.2 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 $9.0 million during the year ended December 31, 2006. The cash flow generated from operating activities of $45.9 million was less than cash used for investing and financing activities of $9.1 million and $45.8 million, respectively. Working capital decreased by $10.0 million to $9.5 million during the year ended December 31, 2006.

Cash Flows — Operating Activities

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

Cash flows from operating activities increased by $3.3 million from $42.6 million for the year ended December 31, 2005 to $45.9 million for the year ended December 31, 2006. This increase is mainly due to $13.5 million additional cash collections from customers on the Alon assets and Intermediate Pipelines purchased in 2005. This increase of cash collections is partially offset by increased operations expense of $2.8 million on these new assets and increased cash payments for interest of $7.1 million, principally on the debt issued for these acquisitions. The remaining decrease in cash flows from operating activities is due to miscellaneous year-over-year changes in collections and payments, offset by lower pre-payments in 2006.

As discussed above, our major shippers are obligated to make deficiency payments to us if we do not receive certain minimum revenue payments. The shippers then have the right to recapture these amounts if future revenues exceed certain levels. During the year ended December 31, 2006, we received cash payments of approximately $5.6 million under these commitments, of which $0.9 million was recaptured in 2006. We collected $1.0 million during the year ended December 31, 2005 related to 2005 shortfalls, which expired without recapture and was recognized as revenue in the year ended December 31, 2006. Another $1.3 million is included in our accounts receivable at December 31, 2006 related to shortfalls produced in the fourth quarter of 2006.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

Cash flows from operating activities increased by $26.7 million from $15.9 million for the year ended December 31, 2004 to $42.6 million for the year ended December 31, 2005. Cash flows from operating activities for 2004 were comparatively low principally because Holly utilized a common treasury function for all of its subsidiaries prior to our formation on July 13, 2004, whereby all cash receipts were deposited in Holly bank accounts and all cash disbursements were made from these common accounts. Thus, prior to our initial public offering, no cash balances were reflected in the accounts of HEP’s predecessor, NPL, other than the cash balances of Rio Grande. Accordingly, $33.0 million of NPL’s revenue and $12.2 million of operations expense prior to formation of HEP were not included in HEP’s cash flows in 2004.

The acquisitions of the Alon assets and the Intermediate Pipelines impacted operating cash flows by providing $21.8 million of customer collections and $4.5 million of expenditures in 2005. Our net interest expense increased $8.9 million, principally for the issuances of Senior Notes to finance the Alon assets and Intermediate Pipelines acquisitions. Also, our expenditures for general and administrative costs

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increased by $2.5 million from 2004 to 2005, due mainly to the fact that Holly did not allocate general and administrative expenses to us prior to our formation in 2004.

Cash Flows — Investing Activities

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

Cash flows used for investing activities decreased by $122.7 million from $131.8 million for the year ended December 31, 2005 to $9.1 million for the year ended December 31, 2006. On February 28, 2005, we closed on the Alon transaction which required $120.0 million in cash plus transaction costs of $2.0 million. Additionally, we issued 937,500 Class B subordinated units valued at $24.7 million to Alon as part of the consideration. See “Alon Transaction” below for additional information. On July 8, 2005, we closed on the acquisition of the Holly Intermediate Pipelines for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. As this was a transaction between entities under common control, we recorded the acquired assets at Holly’s historic book value. This resulted in payment to Holly of a purchase price of $71.9 million in excess of the basis of the assets received, which is included in cash flows from financing activities. See “Holly Intermediate Pipelines Transaction” below for additional information. Additions to properties and equipment for the year ended December 31, 2006 was $9.1 million, an increase of $5.2 million from $3.9 million for the year ended December 31, 2005.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

Cash flows used for investing activities increased by $128.8 million from $3.0 million for the year ended December 31, 2004 to $131.8 million for the year ended December 31, 2005. On February 28, 2005, we closed on the Alon transaction which required $120.0 million in cash plus transaction costs of $2.0 million. Additionally, we issued 937,500 Class B subordinated units valued at $24.7 million to Alon as part of the consideration. See “Alon Transaction” below for additional information. On July 8, 2005, we closed on the acquisition of the Holly Intermediate Pipelines for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. As this was a transaction between entities under common control, we recorded the acquired assets at Holly’s historic book value. This resulted in payment to Holly of a purchase price of $71.9 million in excess of the basis of the assets received, which is included in cash flows from financing activities. See “Holly Intermediate Pipelines Transaction” below for additional information. Additions to properties and equipment for the year ended December 31, 2005 was $3.9 million, an increase of $0.9 million from $3.0 million for the year ended December 31, 2004.

Cash Flows — Financing Activities

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

Cash flows used for financing activities amounted to $45.8 million for the year ended December 31, 2006. This compared to cash flows provided by financing activities of $90.6 million for the year ended December 31, 2005. In February 2005, we received proceeds of $147.4 million from the issuance of Senior Notes in connection with the Alon asset acquisition. Additionally, we used proceeds from the original Senior Note offering to repay $30.0 million of outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. In June 2005, in anticipation of the July Holly Intermediate Pipelines transaction, we received additional proceeds from Senior Notes issued of $33.8 million. See “Senior Notes Due 2015” below for additional information. We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the private sale of 1,100,000 of our common units to a limited number of institutional investors which closed simultaneously with the closing of the acquisition of the Intermediate Pipelines on July 8, 2005. Of the cash paid to Holly for the Intermediate Pipelines, the excess cash paid over the asset basis was $71.9 million. During the year ended December 31, 2006, we paid cash distributions on all units and the general partner interest in the aggregate amount of $43.7 million, an increase of $8.7 million from $35.0 million in distributions paid during the year ended December 31, 2005. Distributions to the minority interest owner in Rio Grande were $1.5 million for the year ended December 31, 2006, a decrease of $0.7 million from $2.2 million for the year months ended December 31, 2005. Other cash flows from financing activities during the year ended December 31, 2005 included an

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additional capital contribution from our general partner of $0.6 million and deferred debt issuance costs incurred of $1.2 million.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

Cash flows provided by financing activities amounted to $90.6 million for the year ended December 31, 2005. This compared to cash flows used in financing activities of $0.5 million in the year ended December 31, 2004. In February 2005, we received proceeds of $147.4 million from the issuance of Senior Notes in connection with the Alon asset acquisition. Additionally, we used proceeds from the original senior note offering to repay $30.0 million of outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. In June 2005, in anticipation of the July 2005 Holly Intermediate Pipelines transaction, we received additional proceeds from Senior Notes issued of $33.9 million. See “Senior Notes Due 2015” below for additional information. We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the private sale of 1,100,000 of our common units to a limited number of institutional investors which closed simultaneously with the closing of the acquisition of the Intermediate Pipelines on July 8, 2005. Of the cash paid to Holly for the Intermediate Pipelines, the excess cash paid over the asset basis was $71.9 million. During 2005, we paid cash distributions on all units and the general partner interest in the aggregate amount of $35.0 million. Other cash flows from financing activities during the year ended December 31, 2005 included an additional capital contribution from our general partner of $0.6 million and deferred debt issuance costs incurred of $1.2 million. We completed our initial public offering of 7,000,000 common units on July 13, 2004, receiving net proceeds of $145.5 million and drawing $25.0 million on our Credit Agreement. The proceeds from these financings were utilized to repay $30.1 million owed to Holly as well as making a $125.6 million distribution to Holly. In addition, we used $3.5 million to pay for offering costs and $1.4 million to pay deferred debt issuance costs associated with our Credit Agreement. We also paid $0.7 million in late 2004 in deferred debt costs relating to the financing of the then pending Alon transaction. Distributions to the minority interest owner in Rio Grande were $2.2 million for the year ended December 31, 2005, a decrease of $1.0 million from $3.2 million for the year months ended December 31, 2004.

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 or construct 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 for a particular capital project may be expended over a period of years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years.

In February 2007, the HLS board of directors authorized a letter of intent with Plains for HEP to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system, now being constructed by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. The pipeline would be owned by a new joint venture company which would be owned 75% by Plains and 25% by HEP. Subject to the

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actual construction cost, HEP would purchase its interest for between $22.0 and $25.5 million in the first quarter of 2008, when the new pipeline system is expected to become fully operational. The pipeline is being built to 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, which is currently flowing on Plains’ Rocky Mountain Pipeline. Our investment in the project is subject to various conditions, including the negotiation and execution of mutually satisfactory definitive agreements. This investment is expected to take the place of a project that we had been considering to construct and operate a new pipeline called the Porcupine Ridge Pipeline to transport crude oil from the Utah terminus of the Frontier Pipeline to Salt Lake City.

We anticipate that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for smaller capital development projects (including the investment in the Utah crude oil pipeline project as described in the preceding paragraph) will be funded with existing cash balances, cash generated by operations and advances under our four-year $100 million senior secured revolving Credit Agreement.

The HLS board of directors is also considering a project to construct a 12-inch pipeline from Salt Lake City to Las Vegas, with service also to the Cedar City, Utah area. The initial capacity of the pipeline would be approximately 62,000 bpd, and it is expected that the capacity could be later increased up to approximately 118,000 bpd by adding pump stations. The cost of the pipeline is expected to be approximately $235 million, and the total cost of the project including terminals is expected to be approximately $300 million. We are currently in the process of soliciting potential shippers for binding commitments through an “open season” extending to the latter part of March 2007, and we expect to make a final decision on whether to proceed with this project based on the level of commitment from shippers. Certain preliminary work has already been carried out on this project by Holly, but as of the date of this report we have not expended HEP funds or committed to do so with respect to the project. If we choose to carry out this project, our financing for the project would include reimbursement to Holly for previous expenditures and assumption of any commitments previously made by Holly with respect to the project, and might also involve an investment in the project by one or more other companies, making our investment proportionately less.

We expect to use the issuance of common units and/or debt securities as the principal means of financing large investments in major capital projects such as the proposed Salt Lake City to Las Vegas pipeline project described in the preceding paragraph.

Credit Agreement

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100.0 million senior secured revolving Credit Agreement. Union Bank of California, N.A. is a lender and serves as administrative agent under this agreement. Upon closing of our initial public offering, we drew $25.0 million under the Credit Agreement, which was outstanding at December 31, 2004.

We amended the Credit Agreement effective February 28, 2005 to allow for the closing of the Alon transaction and the related Senior Notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from the Senior Notes offering, we repaid $30.0 million of outstanding indebtedness under the Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. As of June 17, 2005, we amended the Credit Agreement to restate the definition of certain terms used in the restrictive covenants. Additionally, we amended the Credit Agreement effective July 8, 2005 to allow for the closing of the Holly Intermediate Pipelines transaction as well as to amend certain of the restrictive covenants. As of December 31, 2006, we had no amounts 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 designated for working capital are 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. Up to $5.0 million is available to fund distributions to unitholders.

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We have the right to request an increase in the maximum amount of the Credit Agreement, up to $175.0 million. Such request will become effective if (a) certain conditions specified in the Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

Our obligations under the Credit Agreement are secured by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to our general partner and guaranteed by our wholly-owned subsidiaries.

We may prepay all loans at any time without penalty. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the agreement.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.50% to 2.25%). 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 of 0.375% or 0.500% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At December 31, 2006, we are subject to the 0.500% rate on the $100.0 million of the unused commitment on the Credit Agreement. The agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

The Credit Agreement imposes certain requirements, 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 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.

Senior Notes Due 2015

We financed the $120.0 million cash portion of the consideration for the Alon transaction through our private offering on February 28, 2005 of $150.0 million principal amount of 6.25% Senior Notes due 2015. We used the balance to repay $30.0 million of outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes.

The Senior Notes mature on March 1, 2015 and bear interest at 6.25%. 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. 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.

The $185.0 million principal amount of Senior Notes is recorded at $180.7 on our accompanying consolidated balance sheet at December 31, 2006. The difference is due to the $3.1 million unamortized discount and $1.2 relating to the fair value of the interest rate swap contract discussed below.

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Alon Transaction

The total consideration paid for the Alon pipeline and terminal assets was $120.0 million in cash and 937,500 of our Class B subordinated units which, subject to certain conditions, will convert into an equal number of common units in five years. We financed the cash portion of the Alon transaction through our private offering of the $150.0 million Senior Notes. We used the proceeds of the offering to fund the $120.0 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30.0 million of outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. In connection with the Alon transaction, we entered into the 15-year Alon PTA. 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. The total annual commitment following the March 1, 2006 PPI adjustment, is $20.5 million.

The consideration for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values as determined by an independent appraisal. The aggregate consideration amounted to $146.7 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120.0 million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million, representing the value of the 15-year pipelines and terminals agreement for transportation.

Holly Intermediate Pipelines Transaction

On July 6, 2005, we entered into the Purchase Agreement with Holly to acquire Holly’s two 65-mile parallel Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. On July 8, 2005, we closed on the acquisition for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. We financed the cash portion of the consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of 1,100,000 of our common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal amount of our 6.25% Senior Notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines granted by Holly to us at the time of our initial public offering in July 2004.

In connection with this transaction, we entered into a 15-year pipelines agreement with Holly. Under this agreement, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that, at the agreed tariff rates, will result in minimum funds to us of $11.8 million in the initial contract year. The total annual commitment following the July 1, 2006 PPI adjustment, is $12.4 million.

As this transaction is among entities under common control, we recorded the acquired assets at Holly’s historic book value of $6.8 million. This resulted in payment to Holly of a purchase price of $71.9 million in excess of the basis of the assets received and a $71.9 million reduction of our net partners’ equity.

Contractual Obligations and Contingencies

The following table presents our long-term contractual obligations as of December 31, 2006.

• The pipeline operating lease amounts below reflect the exercise of the first of three 10-year extensions, effective July 2007, 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 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, 2006. 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.

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			Payments Due by Period
			Less than						Over 5
	Total		1 Year		2-3 Years		4-5 Years		Years
	(In thousands)
Long-term debt — principal	$	185,000	$	—	$	—	$	—	$	185,000
Long-term debt — interest		98,281		11,563		23,125		23,125		40,468
Pipeline operating lease		61,401		5,848		11,695		11,695		32,163
Right of way leases		1,793		165		578		80		970
Other		2,174		1,781		393		—		—
Total	$	348,649	$	19,357	$	35,791	$	34,900	$	258,601

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, 2006, 2005 and 2004.

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 2.5% annually over the past 5 calendar years.

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, except that prior to January 1, 2004, pipeline tariff and terminal services fee revenues were not recorded on services utilizing non-FERC regulated pipelines. These revenues had not previously been recognized as the pipelines and terminals were operated as a component of Holly’s petroleum refining and marketing business. Commencing January 1, 2004, we began charging Holly pipeline tariffs and terminal service fees in the amounts set forth in the Holly PTA. 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.

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The only revenues reflected in the historical financial data prior to January 1, 2004 are from (a) third parties who used our pipelines and terminals, (b) Holly’s use of our Artesia, New Mexico to Orla, Texas to El Paso refined product pipeline and (c) Holly’s use of the Lovington crude oil pipelines, which were not contributed to us.

Long-Lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results, and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2006, 2005 and 2004.

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 Standards (“SFAS”) No. 154 “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and SFAS No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principle and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. We adopted this standard effective January 1, 2006. The adoption of this standard did not have a material effect on our financial condition, results of operations and cash flows.

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not anticipate that the adoption of this interpretation will have a material effect on our financial condition, results of operations and cash flows.

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SFAS No. 157 “Fair Value Measurements”

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. This standard is effective for fiscal years beginning after November 15, 2007. We do not anticipate that the adoption of this interpretation will have a material effect on our financial condition, results of operations and cash flows.

RISK MANAGEMENT

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed rate to variable rates. Under the swap agreement, we receive 6.25% fixed rate on the notional amount and pay a variable rate equal to three month LIBOR plus an applicable margin of 1.1575%. The variable rate being paid on the notional amount at December 31, 2006 was 6.5269%, including the applicable margin. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have used the “shortcut” method of accounting prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps.

The fair value of the interest rate swap agreement of $1.2 million is included in “Other long-term liabilities” in our accompanying consolidated balance sheet at December 31, 2006. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is recognized as a reduction of “Long-term debt” on our accompanying consolidated balance sheet at December 31, 2006.

The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

At December 31, 2006, we had an outstanding principal balance on our unsecured Senior Notes of $185.0 million. By means of our interest rate swap contract, we have effectively converted $60.0 million of the Senior Notes from a fixed rate to variable rate. For the fixed rate debt portion of $125.0 million, changes in interest rates would generally affect the fair value of the debt, but not our earnings or cash flows. Conversely, for the variable rate debt portion of $60.0 million, changes in interest rates would generally not impact the fair value of the debt, but may affect our future earnings and cash flows. We estimate a hypothetical 10% change in the yield-to-maturity applicable to our fixed rate debt portion of $125.0 million as of December 31, 2006 would result in a change of approximately $5.2 million in the fair value of the debt. A hypothetical 10% change in the interest rate applicable to our variable rate debt portion of $60.0 million would not have a material effect on our earnings or cash flows.

At December 31, 2006, 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 to any significant degree 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.

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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, 2006 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, 2006, the Partnership maintained effective internal control over financial reporting.

The Partnership’s independent registered public accounting firm has issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting. That report appears on page 53.

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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 management’s assessment, included in the accompanying managements’ report, that Holly Energy Partners, L.P. (the “Partnership”) maintained effective internal control over financial reporting as of December 31 2006, 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. Our responsibility is to express an opinion on management’s assessment and 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Partnership maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related consolidated statements of income, Partners’ equity (deficit), and cash flows for the years ended December 31, 2006 and 2005 (successor), the period from July 13, 2004 through December 31, 2004 (successor), and the period from January 1, 2004 through July 12, 2004 (predecessor), of Holly Energy Partners, L.P. and our report dated February 22, 2007, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 22, 2007

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Index to Consolidated Financial Statements

	Page
	Reference
Report of Independent Registered Public Accounting Firm		55
Consolidated Balance Sheets at December 31, 2006 and 2005		56
Consolidated Statements of Income for the years ended December 31, 2006 and 2005, the period from July 13, 2004 through December 31, 2004, and the period from January 1, 2004 through July 12, 2004		57
Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005, the period from July 13, 2004 through December 31, 2004, and the period from January 1, 2004 through July 12, 2004		58
Consolidated Statements of Partners’ Equity for the years ended December 31, 2006 and 2005, the period from July 13, 2004 through December 31, 2004, and the period from January 1, 2004 through July 12, 2004		59
Notes to Consolidated Financial Statements		60

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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, 2006 and 2005, and the related consolidated statements of income, partners’ equity (deficit), and cash flows for the years ended December 31, 2006 and 2005 (successor), the period from July 13, 2004 through December 31, 2004 (successor), and the period from January 1, 2004 through July 12, 2004 (predecessor). 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.

As described in Note 6 to the consolidated financial statements, in 2005 the Partnership adopted Statement of Financial Accounting Standard No. 123(r), “Share-Based Payments.”

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, 2006 and 2005, and the related consolidated results of its operations and its cash flows, for the years ended December 31, 2006 and 2005 (successor), the period from July 13, 2004 through December 31, 2004 (successor), and the period from January 1, 2004 through July 12, 2004 (predecessor), 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), the effectiveness of Holly Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2006, 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 22, 2007 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 22, 2007

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Holly Energy Partners, L.P.

Consolidated Balance Sheets

	December 31,
	2006			2005
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	11,555		$	20,583
Accounts receivable:
Trade		7,339			3,076
Affiliates		3,518			3,645
		10,857			6,721
Prepaid and other current assets		1,212			1,401
Total current assets		23,624			28,705
Properties and equipment, net		160,484			162,298
Transportation agreements, net		56,821			60,903
Other assets		2,644			2,869
Total assets	$	243,573		$	254,775
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	3,781		$	3,020
Accrued interest		2,941			2,892
Deferred revenue		5,486			1,013
Accrued property taxes		868			1,013
Other current liabilities		1,098			1,313
Total current liabilities		14,174			9,251
Commitments and contingencies		—			—
Long-term debt		180,660			180,737
Other long-term liabilities		1,550			974
Minority interest		10,963			11,753
Partners’ equity (deficit):
Common unitholders (8,170,000 units issued and outstanding at December 31, 2006 and 2005)		176,844			184,568
Subordinated unitholders (7,000,000 units issued and outstanding at December 31, 2006 and 2005)		(70,022	)		(63,153	)
Class B subordinated unitholders (937,500 units issued and outstanding at December 31, 2006 and 2005)		23,469			24,388
General partner interest (2% interest)		(94,065	)		(93,743	)
Total partners’ equity		36,226			52,060
Total liabilities and partners’ equity	$	243,573		$	254,775

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Income

	Successor
							July 13, 2004			Predecessor
	Year Ended			Year Ended			through			January 1,
	December			December			December 31,			2004 through
	31, 2006			31, 2005			2004			July 12, 2004
	(In thousands, except per unit data)
Revenues:
Affiliates	$	52,878		$	44,184		$	17,917		$	27,429
Third parties		36,316			35,936			10,265			12,155
		89,194			80,120			28,182			39,584
Operating costs and expenses:
Operations		28,630			25,332			10,104			13,537
Depreciation and amortization		15,330			14,201			3,241			3,983
General and administrative		4,854			4,047			1,859			1
		48,814			43,580			15,204			17,521
Operating income		40,380			36,540			12,978			22,063
Other income (expense):
Interest income		899			649			65			79
Interest expense		(13,056	)		(9,633	)		(697	)		—
		(12,157	)		(8,984	)		(632	)		79
Income before minority interest		28,223			27,556			12,346			22,142
Minority interest in Rio Grande Pipeline Company		(680	)		(740	)		(956	)		(1,038	)
Net income		27,543			26,816			11,390			21,104
Less:
Net income attributable to Predecessor		—			—			—			21,104
General partner interest in net income		1,710			721			228			—
Limited partners’ interest in net income	$	25,833		$	26,095		$	11,162		$	—
Net income per limited partners’ unit - basic and diluted	$	1.60		$	1.70		$	0.80		$	—
Weighted average limited partners’ units outstanding		16,108			15,356			14,000			—

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows

	Successor
							July 13, 2004			Predecessor
	Year Ended			Year Ended			through			January 1,
	December			December			December			2004 through
	31, 2006			31, 2005			31, 2004			July 12, 2004
	(In thousands)
Cash flows from operating activities
Net income	$	27,543		$	26,816		$	11,390		$	21,104
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		15,330			14,201			3,241			3,983
Minority interest in Rio Grande Pipeline Company		680			740			956			1,038
Amortization of restricted units		927			207			30			—
(Increase) decrease in current assets:
Accounts receivable		(4,263	)		(2,338	)		(7	)		(95	)
Accounts receivable — affiliates		127			(1,594	)		(2,052	)		(21,544	)
Prepaid and other current assets		115			(1,499	)		(323	)		(44	)
Increase (decrease) in current liabilities:
Accounts payable		761			1,305			1,377			(1,293	)
Accounts payable — affiliates		—			—			—			(2,506	)
Accrued interest		49			2,840			—			—
Deferred revenue		4,473			1,013			51			—
Accrued property tax		(144	)		700			(67	)		(72	)
Other current liabilities		(215	)		(20	)		789			(74	)
Other, net		470			257			(14	)		(1	)
Net cash provided by operating activities		45,853			42,628			15,371			496
Cash flows from investing activities
Additions to properties and equipment		(9,107	)		(3,883	)		(305	)		(2,672	)
Acquisitions of pipeline and terminal assets		—			(127,912	)		—			—
Net cash used for investing activities		(9,107	)		(131,795	)		(305	)		(2,672	)
Cash flows from financing activities
Proceeds from issuance of senior notes, net of discounts		—			181,238			—			—
Proceeds from issuance of common units, net of underwriter discount		—			45,100			145,460			—
Distributions to Holly concurrent with initial public offering		—			—			(125,612	)		—
Excess purchase price over contributed basis of intermediate pipelines		—			(71,850	)		—			—
Distributions to partners		(43,670	)		(35,022	)		(6,214	)		—
Borrowings (payback) of short-term of debt — affiliates		—			—			(30,082	)		—
Borrowings (payback) under revolving credit agreement		—			(25,000	)		25,000			—
Costs of issuing common units		—			(349	)		(3,486	)		—
Deferred debt issuance costs		—			(1,228	)		(2,086	)		—
Cash distributions to minority interest		(1,470	)		(2,220	)		(987	)		(2,250	)
Cash contribution from general partner		—			612			—			—
Purchase of units for restricted grants		(634	)		(635	)		(223	)		—
Net cash provided by (used for) financing activities		(45,774	)		90,646			1,770			(2,250	)
Cash and cash equivalents
Increase (decrease) for the period		(9,028	)		1,479			16,836			(4,426	)
Beginning of period		20,583			19,104			2,268			6,694
End of period	$	11,555		$	20,583		$	19,104		$	2,268

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Partners’ Equity (Deficit)

				Successor
										Class B			General
	Predecessor			Common			Subordinated			Subordinated			Partner
	Parent			Units			Units			Units			Interest			Total
	(In thousands)
Predecessor:
Balance December 31, 2003	$	68,860		$	—		$	—		$	—		$	—		$	68,860
Assets and liabilities not contributed to Holly Energy Partners, L.P.		(49,782	)		—			—			—			—			(49,782	)
Net income		21,104			—			—			—			—			21,104
Balance July 12, 2004		40,182			—			—			—			—			40,182
Successor:
Allocation of net parent investment to unitholders		(40,182	)		—			38,606			—			1,576			—
Proceeds from initial public offering, net of underwriter discount		—			145,460			—			—			—			145,460
Costs of issuing common units		—			(3,486	)		—			—			—			(3,486	)
Distributions to partners		—			(3,045	)		(103,657	)		—			(25,124	)		(131,826	)
Purchase of units for restricted grants		—			(222	)		—			—			—			(222	)
Amortization of restricted units		—			30			—			—			—			30
Net income		—			5,581			5,581			—			228			11,390
Balance December 31, 2004		—			144,318			(59,470	)		—			(23,320	)		61,528
Issuance of common units		—			45,100			—			—			—			45,100
Cost of issuing common units		—			(349	)		—			—			—			(349	)
Issuance of Class B subordinated units		—			—			—			24,674			—			24,674
Capital contribution		—			—			—			—			1,591			1,591
Distributions to partners		—			(16,945	)		(15,575	)		(1,617	)		(885	)		(35,022	)
Excess purchase price over contributed basis of intermediate pipelines		—			—			—			—			(71,850	)		(71,850	)
Purchase of units for restricted grants		—			(635	)		—			—			—			(635	)
Amortization of restricted units		—			207			—			—			—			207
Net income		—			12,872			11,892			1,331			721			26,816
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

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006

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 45% owned by Holly Corporation (“Holly”). HEP commenced operations July 13, 2004. Concurrently with the completion of its initial public offering, Navajo Pipeline Co., L.P. (Predecessor) (“NPL”) and its affiliates, a wholly owned subsidiary of Holly, contributed a substantial portion of its assets to HEP. In this document, the words “we”, “our”, “ours” and “us” refer to HEP and NPL collectively unless the context otherwise indicates. See Note 2 for a further description of these transactions.

NPL constitutes HEP’s predecessor. The transfer of ownership of assets from NPL to HEP represented a reorganization of entities under common control and was recorded at NPL’s historical cost. Accordingly, our financial statements include the historical results of operations of NPL prior to the transfer to HEP.

We operate in one business segment — the operation of petroleum pipelines 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”). In July 2005, we acquired the two parallel intermediate feedstock pipelines, which connect the New Mexico refining facilities. 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. In conjunction with Holly’s operation of the Navajo Refinery, we operate refined product pipelines as part of the product distribution network of the Navajo Refinery. Our terminal operations serving the 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 a truck rack at the Woods Cross Refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho.

In February 2005, we acquired from Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport light refined products for Alon’s 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. All significant inter-company transactions and balances have been eliminated. The consolidated financial statements include the financial position and results of operations of pipeline and terminal facilities previously owned by Holly and/or NPL, which were contributed to HEP concurrently with the completion of our initial public offering, as well as the intermediate pipeline assets that were purchased from Holly in July 2005. Both of these acquisitions of assets from Holly were accounted for as transactions among entities under common control. Therefore, the assets were recorded on our balance sheets at Holly’s basis instead of the purchase price or fair value.

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If the assets acquired from Holly upon formation and the intermediate pipelines transaction had been acquired from third parties, the cash payment upon formation and the excess of the intermediate pipeline purchase price over its basis would have been recorded as properties or intangible assets instead of reductions of partners’ equity. Also, the subordinated units issued to Holly would have been recorded at fair value instead of the carryover basis of the contributed assets.

The consolidated financial statements also include financial data, at historical cost, related to the assets owned by Holly and its wholly-owned subsidiaries through July 12, 2004, other than HEP, that were not contributed to us upon completion of our initial public offering.

On June 30, 2003, we acquired an additional 45% partnership interest in Rio Grande, bringing our ownership to 70%. Commencing July 1, 2003, the results of Rio Grande were consolidated and reflected in our consolidated financial statements.

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Cash 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 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 pipeline and terminal facilities, 23 to 33 years for regulated 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

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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, 2006, an asset retirement obligation of $0.3 million is included in “Other long-term liabilities” in our consolidated balance sheets.

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.

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.

Income Taxes

As a partnership, we are an entity that is not subject to income taxes. Therefore, there is no provision for income taxes included in our consolidated financial statements. Taxable income, gain, loss and deductions are allocated to the unitholders who are responsible for payment of any income taxes thereon.

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

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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, and after deducting net income attributable to the Predecessor (before July 13, 2004), by the weighted-average number of units outstanding for each class of limited partners’ units.

Recent Accounting Pronouncements

Statement of Financial Accounting Standards (“SFAS”) No. 154 “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and SFAS No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principle and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. We adopted this standard effective January 1, 2006. The adoption of this standard did not have a material effect on our financial condition, results of operations and cash flows.

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not anticipate that the adoption of this interpretation will have a material effect on our financial condition, results of operations and cash flows.

SFAS No. 157 “Fair Value Measurements”

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. This standard is effective for fiscal years beginning after November 15, 2007. We do not anticipate that the adoption of this interpretation will have a material effect on our financial condition, results of operations and cash flows.

Note 2: Initial Public Offering of HEP

HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in West Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande.

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On July 7, 2004, we priced 6,100,000 common units for the initial public offering; and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $145.5 million, net of $10.3 million underwriting commissions. After the offering, Holly, through a subsidiary, owned a 51% interest in HEP, including the general partner interest. The initial public offering represented the sale of a 49% interest in HEP.

All of our initial assets were contributed by Holly and its subsidiaries in exchange for: (a) an aggregate of 7,000,000 subordinated units, representing 49% limited partner interests in HEP, (b) incentive distribution rights (as set forth in HEP’s partnership agreement), (c) the 2% general partner interest, and (d) an aggregate cash distribution of $125.6 million.

The following table presents the assets and liabilities of our predecessor immediately prior to contributing assets to HEP, the assets and liabilities contributed to HEP, and the predecessor’s assets and liabilities that were not contributed to HEP:

	Navajo Pipeline		Contributed to
	Co., L.P.		Holly Energy
	(Predecessor)		Partners, L.P.		Not
	July 12, 2004		July 13, 2004		Contributed
	(In thousands)
Cash	$	2,268	$	2,268	$	—
Accounts receivable — trade		850		800		50
Accounts receivable — affiliates		51,934		—		51,934
Prepaid and other current assets		292		173		119
Properties and equipment, net		95,337		76,605		18,732
Transportation agreement, net		5,692		5,692		—
Total assets		156,373		85,538		70,835
Accounts payable — trade		1,452		339		1,113
Accounts payable — affiliates		18,819		—		18,819
Accrued liabilities		1,018		534		484
Short-term debt		30,082		30,082		—
Non-current liabilities		1,775		1,138		637
Minority interest		13,263		13,263		—
Total liabilities		66,409		45,356		21,053
Net Assets	$	89,964	$	40,182	$	49,782

We used the proceeds of the public offering and $25.0 million drawn under our credit facility agreement to: establish $9.9 million working capital for HEP, distribute $125.6 million to Holly, repay $30.1 million of short-term debt to Holly, pay $13.8 million underwriting commissions and other offering costs, and pay $1.4 million of deferred debt issuance costs related to the credit facility.

In connection with the offering, we entered into a 15-year pipelines and terminals agreement expiring 2019 with Holly and several of its subsidiaries (the “Holly PTA”) under which they agreed generally to transport or terminal volumes on certain of our initial facilities that will result in funds to HEP that will equal or exceed a specified minimum revenue amount annually (which is currently $38.5 million and adjusts upward each year based on the producer price index (“PPI”)) over the term of the agreement. Under certain circumstances, generally dealing with Holly shutting down or reconfiguring its refineries, Holly’s minimum revenue commitment to us could be reduced.

We also entered into an omnibus agreement with Holly and certain of its subsidiaries that became effective July 13, 2004 (the “Omnibus Agreement”) that specifies the services that Holly provides to us. Under the Omnibus Agreement, Holly charges us $2.0 million annually for general and administrative services that it provides, including but not limited to: executive, finance, legal, information technology and administrative services.

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Note 3: Acquisitions

Alon Transaction

On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport and terminal light refined products for Alon’s refinery in Big Spring, Texas.

The total consideration paid for these pipeline and terminal assets was $120.0 million in cash and 937,500 of our Class B subordinated units which, subject to certain conditions, will convert into an equal number of common units on February 28, 2010. We financed the Alon transaction with a portion of the proceeds of our private offering of $150.0 million principal amount of 6.25% Senior Notes due 2015 (see Note 7 for further information on the Senior Notes). In connection with the Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon expiring 2020 (the “Alon PTA”). Under this agreement, 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, 2006 PPI adjustment, the volume commitments by Alon under the Alon PTA will produce at least $20.5 million of revenue for the twelve months ending February 28, 2007. The agreed upon tariffs will increase or decrease each year at a rate equal to the percentage change in the PPI, but not below the initial tariffs. 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. We granted Alon a second mortgage on the pipelines and terminals acquired from Alon to secure certain of Alon’s rights under the Alon PTA. Alon has a right of first refusal to purchase the pipelines and terminals if we decide to sell them in the future. Additionally, we entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon, 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.

The consideration for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The allocation of the consideration is based on an independent appraisal. The aggregate consideration amounted to $146.7 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120.0 million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million, representing the allocated value of the 15-year Alon PTA. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

Holly Intermediate Pipelines Transaction

On July 6, 2005, we entered into a definitive purchase agreement (the “Purchase Agreement”) with Holly to acquire Holly’s two parallel intermediate feedstock pipelines (the “Intermediate Pipelines”) which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. On July 8, 2005, we closed on the acquisition for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. We financed the cash portion of the consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of 1,100,000 of our common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal amount of our 6.25% Senior Notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines granted by Holly to us at the time of our initial public offering in July 2004.

In connection with this transaction, we entered into a 15-year pipelines agreement with Holly (the “Holly IPA”) which expires in 2020. Under this agreement, Holly agreed to transport volumes of intermediate

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products on the Intermediate Pipelines that would result in initial minimum funds to us of $11.8 million each year that will change annually based on changes in the PPI. Following the July 1, 2006 PPI adjustment, the volume commitments by Holly under the Holly IPA will result in minimum funds to us of $12.4 million annually. The agreed upon tariff is adjusted each year at a rate equal to the percentage change in the PPI, but the minimum commitment will not decrease as a result of a decrease in the PPI. Holly’s minimum revenue commitment applies only to the Intermediate Pipelines, and Holly will not be able to spread its minimum revenue commitment among pipeline assets HEP already owns or subsequently acquires. If Holly fails to meet its minimum revenue commitment 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. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met. The Holly IPA may be extended by the mutual agreement of the parties.

We agreed to expend up to $3.5 million to expand the capacity of the Intermediate Pipelines to meet the needs of Holly’s expansion of their Navajo Refinery. As of December 31, 2006, this expansion project was complete and no further expenditures are expected under this obligation. If new laws or regulations are enacted that require us to make substantial and unanticipated capital expenditures with regard to the Intermediate Pipelines, we have the right to amend the tariff rates to recover our costs of complying with these new laws or regulations (including a reasonable rate of return). Under certain circumstances, either party may temporarily suspend its obligations under the Holly IPA. We granted Holly a second mortgage on the Intermediate Pipelines to secure certain of Holly’s rights under the Holly IPA. Holly has agreed to provide $2.5 million of additional indemnification above the initial $15.0 million of indemnification under the Omnibus Agreement that previously provided for environmental noncompliance and remediation liabilities occurring or existing before the closing date of the Purchase Agreement, bringing the total indemnification provided to us from Holly to $17.5 million. Of this total, indemnification above $15.0 million relates solely to the Intermediate Pipelines.

As this transaction was among entities under common control, we recorded the acquired assets at Holly’s historic book value of $6.8 million. The $71.9 million excess of the purchase price over the historic book value is recorded as a reduction to partners’ equity for financial accounting purposes.

Note 4: Properties and Equipment

	December 31,
	2006		2005
	(In thousands)
Pipelines and terminals	$	194,008	$	184,464
Land and right of way		22,486		22,163
Other		6,947		5,728
Construction in progress		1,539		2,792
		224,980		215,147
Less accumulated depreciation		64,496		52,849
	$	160,484	$	162,298

During the years ended December 31, 2006 and 2005, we did not capitalize any interest related to major construction projects.

Note 5: Transportation Agreements

The costs of two transportation agreements are recorded on our consolidated balance sheets at December 31, 2006:

• Costs incurred by Rio Grande in constructing certain pipeline and terminal facilities located in Mexico, which were then contributed to an affiliate of Pemex, the national oil company of Mexico. In exchange, Rio Grande received a 10-year transportation agreement from BP plc (“BP”) expiring in 2007. This asset is being amortized over the 10-year term of the agreement.

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• A portion of the total purchase price of the Alon assets was allocated to the transportation agreement asset based on the fair value appraisal provided by an independent firm. 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 carrying amounts of the transportation agreements are as follows:

	December 31,
	2006		2005
	(In thousands)
Rio Grande transportation agreement	$	20,836	$	20,836
Alon transportation agreement		59,933		59,933
		80,769		80,769
Less accumulated amortization		23,948		19,866
	$	56,821	$	60,903

Note 6: Employees, Retirement and Benefit Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., 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 benefits costs for the years ended December 31, 2006, 2005 and 2004 was $1.4 million, $0.9 million and $0.8 million, respectively. Included in these amounts are retirement benefit costs of $0.5 million, $0.4 million and $0.3 million for the years ended December 31, 2006, 2005 and 2004, respectively.

We have adopted a Long-Term Incentive Plan for employees, consultants and 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, 2006, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $927,000, $225,000 and $30,000 for the years ended December 31, 2006, 2005 and 2004, 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, 2006, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 291,491 had not yet been granted.

We elected early adoption of SFAS No. 123 (revised) on July 1, 2005, based on modified prospective application. The effect of this change in accounting principle was immaterial to our financial condition and results of operations.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees, consultants 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.

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A summary of restricted unit activity as of December 31, 2006, and changes during the year ended December 31, 2006 is presented below:

						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Grant-Date		Contractual	Value
Restricted Units	Grants			Fair Value		Term	($000)
Outstanding at December 31, 2005 (not vested)		20,926		$	40.98
Granted		15,871			39.18
Forfeited		(200	)		—
Vesting and transfer of full ownership to recipients		—			—
Outstanding at December 31, 2006 (not vested)		36,597		$	40.21	1.25 years	$	1,473

There were no restricted units vested or transferred to recipients during the years ended December 31, 2006 and 2005. As of December 31, 2006, there was $0.3 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 1.25 years.

In 2006, we paid $0.6 million for the purchase of 15,671 of our common units in the open market for the recipients of all 2006 restricted unit grants.

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. The amount payable under these grants is 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 initial performance unit grant was payable in cash. As of February 10, 2006, we amended the existing performance unit agreements to provide payment of these awards in HEP common units rather than payment in cash. The performance criteria were not amended. Until this conversion to equity payment, the fair value of each performance unit award was revalued quarterly based on our valuation model and the corresponding expense was amortized over the vesting periods. Upon conversion to equity payment, we established the fair value of each performance unit and are now amortizing that amount over the vesting period.

In addition to revising the existing performance unit agreements, we granted 12,501 performance units to certain officers in February 2006. These units will vest over a three-year performance period ending December 31, 2008, 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

The fair value of the performance units is based on an expected cash flow approach at the grant date. The analysis utilizes the unit price, distribution yield, historical total returns as of the measurement date, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns, and comparison of expected total returns with the peer group. The expected total return and historical standard deviation is applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns. The range of inputs reflects changes in the remaining life of the performance units and changes in market conditions between measurement dates. The inputs affecting the range of expected total returns for HEP and the peer group are based on a capital asset pricing model utilizing information available at each measurement date.

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Data Elements Used in Analysis
Closing price of HEP common units February 10, 2006	$	39.55
Latest quarterly distribution per limited unit	$	0.64
Risk-free rate		4.86	%

The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:

	Expected Return	Standard Deviation
Company	on Equity	(Monthly)
HEP	13.75%	7.6%
Peer group	9.75% to 11.25%	4.3% to 5.4%

A summary of performance unit activity as of December 31, 2006, and changes during the year ended December 31, 2006 is presented below:

	Payable			Payable
Performance Units	In Cash			In Units
Outstanding at January 1, 2006 (not vested)		1,515			—
Conversion to unit payment		(1,515	)		1,515
Vesting and payment of units to recipients		—			—
Granted		—			12,501
Forfeited		—			—
Outstanding at December 31, 2006 (not vested)		—			14,016

There were no payments for performance units vesting during the years ended December 31, 2006, 2005 and 2004. Based on the weighted average fair value at December 31, 2006 of $48.93, there was $24,326 of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.9 years.

Note 7: Debt

Credit Agreement

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100.0 million senior secured revolving credit agreement (the “Credit Agreement”). Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. During 2005, amendments were made to the Credit Agreement to allow for the closing of the Alon transaction and the related senior notes offering, the closing of the Holly Intermediate Pipelines transaction and to amend certain of the restrictive covenants. As of December 31, 2006 and December 31, 2005, we had no amounts 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 designated for working capital are 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. Up to $5.0 million is available to fund distributions to unitholders.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $175.0 million. Such request will become effective if (a) certain conditions specified in the Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

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Our obligations under the Credit Agreement are secured by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to our general partner and guaranteed by our wholly-owned subsidiaries.

We may prepay all loans at any time without penalty. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the agreement.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.50% to 2.25%). 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 of 0.375% or 0.500% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At December 31, 2006, we are subject to the 0.500% rate on the $100.0 million of the unused commitment on the Credit Agreement. The agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

The Credit Agreement imposes certain requirements, 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 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.

Senior Notes Due 2015

We financed the $120.0 million cash portion of the Alon transaction through our private offering on February 28, 2005 of $150.0 million principal amount of 6.25% Senior Notes due 2015 (“Senior Notes”). We used the balance to repay $30.0 million of then outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction.

We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes.

On July 28, 2005, we filed a registration statement to allow the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the SEC with substantially identical terms, which exchange was completed in October 2005.

The Senior Notes mature on March 1, 2015 and bear interest at 6.25%. 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. 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.

The $185.0 million principal amount of Senior Notes is recorded at $180.7 million in our consolidated balance sheets at December 31, 2006. The difference of $4.3 million is due to $3.1 million of unamortized discount and $1.2 million relating to the fair value of the interest rate swap contract discussed below.

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Interest Rate Risk Management

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed rate to variable rates. The interest rate on the $60.0 million notional amount is equal to three month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 6.292% on $60.0 million of the debt during the year ended December 31, 2006. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have used the “shortcut” method of accounting prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps.

The fair value of our interest rate swap of $1.2 million and $0.8 million is included in “Other long-term liabilities” in our consolidated balance sheets at December 31, 2006 and 2005, respectively. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is recognized as a reduction of “Long-term debt” in our consolidated balance sheets at December 31, 2006 and 2005.

Other Debt Information

	Year Ended
	December 31,
	2006		2005
	(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swap	$	11,588	$	8,245
Credit Agreement		—		164
Amortization of discount and deferred issuance costs		968		785
Commitment fees		500		439
Net interest expense	$	13,056	$	9,633
Cash paid for interest(1)	$	11,912	$	6,793

(1) Excludes effect of cash received under our interest rate swap agreement of $3.8 million and $1.7 million for the years ended December 31, 2006 and 2005, respectively.

We estimate that the fair value of our Senior Notes was $175.3 million at December 31, 2006, based on a determination by a third-party investment firm.

Note 8: Commitments and Contingencies

We lease certain facilities, pipelines and rights of way under operating leases, most of which contain renewal options. In June 2006, we exercised the first of three 10-year renewal options on our lease agreement for the refined products pipeline between White Lakes Junction and Kutz Station in New Mexico. This extension will become effective July 2007, immediately upon expiration of the original lease term. The right of way agreements have various termination dates through 2053.

As of December 31, 2006, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year, including the first 10-year operating lease extension exercised in June 2006, are as follows (excluding the second and third 10-year lease extensions, which are likely to be exercised):

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Year Ending
December 31,	$000’s
2007	$	6,154
2008		6,449
2009		5,965
2010		5,891
2011		5,884
Thereafter		33,133
Total	$	63,476

Rental expense charged to operations was $5.9 million, $5.6 million and $5.3 million in the years ended December 31, 2006, 2005 and 2004, 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 9: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly, Alon and 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:

	Year Ended December 31,
	2006			2005			2004
Holly		59	%		55	%		67	%
Alon		28	%		30	%		10	%
BP		9	%		11	%		18	%

Note 10: Related Party Transactions

Holly

We have related party transactions with Holly for pipeline and terminal revenues, certain employee costs, insurance costs, and administrative costs under the Holly PTA, Holly IPA and Omnibus Agreement (see Notes 2 and 3). Additionally, we received interest income from Holly during the year ended December 31, 2004, based on common treasury accounts prior to our initial public offering on July 13, 2004. Since that date, we maintain our own treasury accounts separate from Holly.

• Pipeline and terminal revenues received from Holly were $52.9 million, $44.2 million and $45.3 million for the years ended December 31, 2006, 2005 and 2004, respectively. These amounts include the revenues received under the Holly PTA and Holly IPA, as well as revenues received by the predecessor prior to formation in July 2004.

• Holly charged general and administrative services under the Omnibus Agreement of $2.0 million for the years ended December 31, 2006 and 2005 and $0.9 million for the year ended December 31, 2004.

• We reimbursed Holly for costs of employees supporting our operations of $7.7 million, $6.5 million and $2.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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•	In the years ended December 31, 2006 and 2005, Holly reimbursed $0.2 million to us for certain costs paid on their behalf. In the year ended December 31, 2004, we reimbursed Holly $3.9 million for certain formation, debt issuance and other costs paid on our behalf.
•	In the years ended December 31, 2006, 2005 and 2004, we distributed $20.3 million, $16.5 million and $3.2 million, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest.
•	We acquired the Intermediate Pipelines from Holly in July 2005, which resulted in payment to Holly of a purchase price of $71.9 million in excess of the basis of the assets received. See Note 3 for further information on the Intermediate Pipelines transaction.
•	In the year ended December 31, 2004, we distributed $125.6 million to Holly concurrent with our initial public offering and we repaid $30.1 million to Holly for short-term borrowings that originated in 2003.
•	Our net accounts receivable from Holly were $3.5 million and $3.6 million at December 31, 2006 and 2005, respectively.
•	As described under “Holly Intermediate Pipelines Transaction” in Note 3 above, under the Holly IPA, Holly agreed to transport volumes of products on the Intermediate Pipelines that will result in minimum funds to us, adjusted annually for increases in PPI. If Holly fails to meet its minimum commitment in any quarter, Holly is required to pay cash for the shortfall. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligation for that quarter is met.
	Holly has failed to meet its minimum revenue commitment for each of the first six quarters of the Holly IPA. We have charged Holly $3.4 million for these shortfalls to date, $0.2 million and $0.5 million of which are included in affiliate accounts receivable at December 31, 2006 and 2005, respectively.
	We recognized the $1.0 million shortfall for the year ended December 31, 2005 as additional revenues in the consolidated statement of income for the year ended December 31, 2006, as Holly did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at December 31, 2006 and 2005 includes $2.4 million and $1.0 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, 2006.

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 is the sole customer of Rio Grande. BP’s agreement to ship on the Rio Grande pipeline expires in July 2007, and will continue year-to-year thereafter unless cancelled by either party prior to the beginning of the previous contract year. We recorded revenues from them of $8.4 million, $8.8 million and $12.4 million in the years ended December 31, 2006, 2005 and 2004, respectively.

• Rio Grande paid distributions to BP of $1.5 million, $2.2 million and $3.2 million in the years ended December 31, 2006, 2005 and 2004, respectively.

• Included in our accounts receivable — trade at December 31, 2006 and 2005 were $2.1 million and $0.5 million, respectively, which represented the receivable balance of Rio Grande from BP.

Alon

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.

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• Subsequent to the issuance of these units, we recognized $18.0 million and $17.6 million of revenues for pipeline transportation terminalling services under the Alon PTA and $6.9 and $5.6 million under a pipeline capacity lease for the years ended December 31, 2006 and 2005, respectively. The capacity lease agreements have remaining terms ranging from one and one-half to three and one-half years.

• We paid $2.4 million and $1.6 million to Alon for distributions on our Class B subordinated units in the years ended December 31, 2006 and 2005, respectively.

• Included in our accounts receivable — trade at December 31, 2006 and 2005 were $5.0 million and $2.4 million, respectively, which represented the receivable balance from Alon.

• “Deferred revenue” includes $3.1 million of minimum revenue commitments under the Alon PTA at December 31, 2006.

Note 11: Partners’ Equity, Allocations and Cash Distributions

Issuances of units

Upon the closing of our initial public offering on July 13, 2004, Holly received 7,000,000 subordinated units, which constituted 49% ownership of us at that time, and a 2% general partner interest. 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 will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in its partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009.

The Holly subordinated units may convert to common units on a one-for-one basis when certain conditions are met. The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and general partner will receive.

As partial consideration in the Alon transaction in the first quarter of 2005, we issued 937,500 of our Class B subordinated units at a fair value of $24.7 million. Additionally, our general partner contributed $0.6 million as an additional capital contribution to maintain its 2% general partner interest.

We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the private sale of 1,100,000 of our common units to a limited number of institutional investors which closed on July 8, 2005. On September 2, 2005, we filed a registration statement with the SEC using a “shelf” registration process which allows the institutional investors to freely transfer their units. Additionally under this shelf process, we may offer from time to time up to $800.0 million 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

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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.

In connection with the Intermediate Pipelines transaction, we issued 70,000 common units to Holly. We also received a portion of the Intermediate Pipeline assets with $1.0 million book value as a capital contribution from HEP Logistics Holdings, L.P. in order to maintain their 2% general partner interest.

As a result of these transactions, Holly’s total ownership interest was reduced from 51% at the time of our initial public offering to 45% in July 2005 following the Intermediate Pipelines transaction.

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

Concurrent with our initial public offering in July 2004, we distributed $125.6 million to Holly and its subsidiaries. See Note 2 for additional information. In July 2005, our cash payment to Holly in excess of the basis of the assets received in the acquisition of the Intermediate Pipelines was recorded as a reduction to our general partner’s equity in the amount of $71.9 million. See Note 3 for further discussion of this transaction.

We intend to 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 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.

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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	%

In November 2004, we paid our first regular cash distribution for the third quarter of 2004 of $0.435 per unit, based on the minimum quarterly cash distribution of $0.50 prorated for the period since the initial public offering on July 13, 2004.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for each period in which declared.

					July 13, 2004
	Year Ended		Year Ended		through
	December 31,		December 31,		December 31,
	2006		2005		2004
	(In thousands, except per unit data)
General partner interest	$	850	$	697	$	124
General partner incentive distribution		1,182		188		—
Total general partner distribution		2,032		885		124
Limited partner distribution		41,638		34,137		6,090
Total regular quarterly cash distribution	$	43,670	$	35,022	$	6,214
Cash distribution per unit applicable to limited partners	$	2.585	$	2.225	$	0.435

On January 30, 2007, we announced a cash distribution for the fourth quarter of 2006 of $0.675 per unit. The distribution is payable on all common, subordinated, and general partner units and was paid February 14, 2007 to all unitholders of record on February 6, 2007. The aggregate amount of the distribution was $11.5 million, including $0.4 million paid to the general partner as an incentive distribution.

As a master limited partnership, we distribute our available cash, which exceeds 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.

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Note 12: 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, 2006
Revenues	$	22,438	$	18,527	$	22,899	$	25,330	$	89,194
Operating income	$	10,312	$	6,028	$	10,801	$	13,239	$	40,380
Net income	$	7,135	$	2,998	$	7,751	$	9,659	$	27,543
Limited partners’ interest in net income	$	6,808	$	2,679	$	7,263	$	9,083	$	25,833
Net income per limited partner unit — basic and diluted	$	0.42	$	0.17	$	0.45	$	0.56	$	1.60
Distributions declared per limited partner unit	$	0.625	$	0.640	$	0.655	$	0.665	$	2.585
Year ended December 31, 2005
Revenues	$	16,513	$	19,521	$	21,517	$	22,569	$	80,120
Operating income	$	7,785	$	8,234	$	10,185	$	10,336	$	36,540
Net income	$	6,326	$	6,041	$	7,292	$	7,157	$	26,816
Limited partners’ interest in net income	$	6,200	$	5,920	$	7,084	$	6,891	$	26,095
Net income per limited partner unit — basic and diluted	$	0.43	$	0.40	$	0.44	$	0.43	$	1.70
Distributions declared per limited partner unit	$	0.500	$	0.550	$	0.575	$	0.600	$	2.225

Note 13: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent”) under the 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 which 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, 2006	Parent			Subsidiaries		Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	9,819	$	1,734		$	—		$	11,555
Accounts receivable		—			8,772		2,085			—			10,857
Intercompany accounts receivable (payable)		(78,952	)		79,144		(192	)		—			—
Prepaid and other current assets		203			1,009		—			—			1,212
Total current assets		(78,747	)		98,744		3,627			—			23,624
Properties and equipment, net		—			127,357		33,127			—			160,484
Investment in subsidiaries		298,872			25,581		—			(324,453	)		—
Transportation agreements, net		—			56,271		550			—			56,821
Other assets		1,453			1,191		—			—			2,644
Total assets	$	221,578		$	309,144	$	37,304		$	(324,453	)	$	243,573
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	3,356	$	425		$	—		$	3,781
Accrued interest		2,941			—		—			—			2,941
Deferred revenue		—			5,486								5,486
Accrued property taxes		—			726		142			—			868
Other current liabilities		516			389		193			—			1,098
Total current liabilities		3,457			9,957		760			—		��	14,174
Long-term debt		180,660			—		—			—			180,660
Other long-term liabilities		1,235			315		—			—			1,550
Minority interest		—			—		—			10,963			10,963
Partners’ equity		36,226			298,872		36,544			(335,416	)		36,226
Total liabilities and partners’ equity	$	221,578		$	309,144	$	37,304		$	(324,453	)	$	243,573

Condensed Consolidating Balance Sheet
				Guarantor		Non-
December 31, 2005	Parent			Subsidiaries		Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	17,770	$	2,811		$	—		$	20,583
Accounts receivable		—			6,206		515			—			6,721
Intercompany accounts receivable (payable)		(21,182	)		21,458		(276	)		—			—
Prepaid and other current assets		232			1,169		—			—			1,401
Total current assets		(20,948	)		46,603		3,050			—			28,705
Properties and equipment, net		—			128,077		34,221			—			162,298
Investment in subsidiaries		256,416			27,423		—			(283,839	)		—
Transportation agreements, net		—			58,269		2,634			—			60,903
Other assets		1,594			1,275		—			—			2,869
Total assets	$	237,062		$	261,647	$	39,905		$	(283,839	)	$	254,775
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	2,666	$	354		$	—		$	3,020
Accrued interest		2,892			—		—			—			2,892
Deferred revenue		—			1,013		—			—			1,013
Accrued property taxes		—			837		176			—			1,013
Other current liabilities		594			520		199			—			1,313
Total current liabilities		3,486			5,036		729			—			9,251
Long-term debt		180,737			—		—			—			180,737
Other long-term liabilities		779			195		—			—			974
Minority interest		—			—		—			11,753			11,753
Partners’ equity		52,060			256,416		39,176			(295,592	)		52,060
Total liabilities and partners’ equity	$	237,062		$	261,647	$	39,905		$	(283,839	)	$	254,775

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Condensed Consolidating Statement of Income	Successor
				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 income (expense)		(12,119	)		(132	)		94		—			(12,157	)
Minority interest		—			—			—		(680	)		(680	)
Net income	$	27,543		$	42,456		$	2,268	$	(44,724	)	$	27,543

Condensed Consolidating Statement of Income	Successor
				Guarantor			Non-
Year ended December 31, 2005	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	44,184		$	—		$	—		$	44,184
Third parties		—			28,000			8,770			(834	)		35,936
		—			72,184			8,770			(834	)		80,120
Operating costs and expenses:
Operations		—			23,270			2,896			(834	)		25,332
Depreciation and amortization		—			10,824			3,377			—			14,201
General and administrative		1,966			2,064			17			—			4,047
		1,966			36,158			6,290			(834	)		43,580
Operating income (loss)		(1,966	)		36,026			2,480			—			36,540
Equity in earnings of subsidiaries		37,410			1,728			—			(39,138	)		—
Interest income (expense)		(8,628	)		(344	)		(12	)		—			(8,984	)
Minority interest		—			—			—			(740	)		(740	)
Net income	$	26,816		$	37,410		$	2,468		$	(39,878	)	$	26,816

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Condensed Consolidating Statement of Income	Successor
				Guarantor			Non-
July 13, 2004 through December 31, 2004	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	17,917		$	—		$	—		$	17,917
Third parties		—			4,435			5,830			—			10,265
		—			22,352			5,830			—			28,182
Operating costs and expenses:
Operations		—			9,144			960			—			10,104
Depreciation and amortization		—			1,660			1,581			—			3,241
General and administrative		896			863			100			—			1,859
		896			11,667			2,641			—			15,204
Operating income (loss)		(896	)		10,685			3,189			—			12,978
Equity in earnings of subsidiaries		12,286			2,232			—			(14,518	)		—
Interest income (expense)		—			(631	)		(1	)		—			(632	)
Minority interest		—			—			—			(956	)		(956	)
Net income	$	11,390		$	12,286		$	3,188		$	(15,474	)	$	11,390

Condensed Consolidating Statement of Income	Predecessor
			Guarantor		Non-
January 1, 2004 through July 12, 2004	Parent		Subsidiaries		Guarantor		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—	$	27,429	$	—	$	—		$	27,429
Third parties		—		5,541		6,614		—			12,155
		—		32,970		6,614		—			39,584
Operating costs and expenses:
Operations		—		12,178		1,359		—			13,537
Depreciation and amortization		—		2,186		1,797		—			3,983
General and administrative		—		—		1		—			1
		—		14,364		3,157		—			17,521
Operating income		—		18,606		3,457		—			22,063
Equity in earnings of subsidiaries		—		2,420		—		(2,420	)		—
Interest income		—		78		1		—			79
Minority interest		—		—		—		(1,038	)		(1,038	)
Net income	$	—	$	21,104	$	3,458	$	(3,458	)	$	21,104

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Condensed Consolidating Statement of	Successor
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
Acquisitions of pipeline and terminal assets		—			—			—			—			—
Additions to properties and equipment		—			(8,881	)		(226	)		—			(9,107	)
Investments in subsidiaries, net		—			—			—			—			—
		—			(8,881	)		(226	)		—			(9,107	)
Cash flows from financing activities
Contributions from (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
Increase (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

Condensed Consolidating Statement of	Successor
Cash Flows
				Guarantor			Non-
Year Ended December 31, 2005	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	7,566		$	33,945		$	6,297		$	(5,180	)	$	42,628
Cash flows from investing activities
Acquisitions of pipeline and terminal assets		(125,801	)		(2,111	)		—			—			(127,912	)
Additions to properties and equipment		—			(3,838	)		(45	)		—			(3,883	)
Investments in subsidiaries, net		(1	)		—			—			1			—
		(125,802	)		(5,949	)		(45	)		1			(131,795	)
Cash flows from financing activities
Proceeds from issuance of senior notes, net of discounts		181,238			—			—			—			181,238
Proceeds from issuance of common units, net of underwriter discount		45,100			—			—			—			45,100
Excess purchase price over contributed basis of intermediate pipelines		(71,850	)		—			—			—			(71,850	)
Contributions from (distributions to) partners		(34,410	)		1			(7,400	)		7,399			(34,410	)
Borrowings (payback) of debt, net		—			(25,000	)		—			—			(25,000	)
Cash distributions to minority interest		—			—			—			(2,220	)		(2,220	)
Other financing activities, net		(1,842	)		(370	)		—			—			(2,212	)
		118,236			(25,369	)		(7,400	)		5,179			90,646
Cash and cash equivalents
Increase (decrease) for the year		—			2,627			(1,148	)		—			1,479
Beginning of year		2			15,143			3,959			—			19,104
End of year	$	2		$	17,770		$	2,811		$	—		$	20,583

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Condensed Consolidating Statement of	Successor
Cash Flows
				Guarantor			Non-
July 13, 2004 through December 31, 2004	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	5,159		$	7,472		$	5,043		$	(2,303	)	$	15,371
Cash flows from investing activities
Additions to properties and equipment		—			(243	)		(62	)		—			(305	)
Investments in subsidiaries, net		(15,082	)		—			—			15,082			—
		(15,082	)		(243	)		(62	)		15,082			(305	)
Cash flows from financing activities
Proceeds from issuance of common units, net of underwriter discount		145,460			—			—			—			145,460
Distributions to Holly concurrent with IPO		(125,612	)		—			—			—			(125,612	)
Contributions from (distributions to) partners		(6,214	)		15,082			(3,290	)		(11,792	)		(6,214	)
Borrowings (payback) of debt, net		—			(5,082	)		—			—			(5,082	)
Cash distributions to minority interest		—			—			—			(987	)		(987	)
Other financing activities, net		(3,709	)		(2,086	)		—			—			(5,795	)
		9,925			7,914			(3,290	)		(12,779	)		1,770
Cash and cash equivalents
Increase for the period		2			15,143			1,691			—			16,836
Beginning of period		—			—			2,268			—			2,268
End of period	$	2		$	15,143		$	3,959		$	—		$	19,104

Condensed Consolidating Statement of	Predecessor
Cash Flows
			Guarantor			Non-
January 1, 2004 through July 12, 2004	Parent		Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	—	$	2,017		$	3,729		$	(5,250	)	$	496
Cash flows from investing activities
Additions to properties and equipment		—		(2,017	)		(655	)		—			(2,672	)
		—		(2,017	)		(655	)		—			(2,672	)
Cash flows from financing activities
Contributions from (distributions to) partners		—		—			(7,500	)		7,500			—
Cash distributions to minority interest		—		—			—			(2,250	)		(2,250	)
		—		—			(7,500	)		5,250			(2,250	)
Cash and cash equivalents
Decrease for the period		—		—			(4,426	)		—			(4,426	)
Beginning of period		—		—			6,694			—			6,694
End of period	$	—	$	—		$	2,268		$	—		$	2,268

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Note 14: Subsequent Events

In February 2007, the HLS board of directors authorized a letter of intent with Plains All American Pipeline, L.P. (“Plains”) for us to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system, now being constructed by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. The pipeline would be owned by a new joint venture company which would be owned 75% by Plains and 25% by HEP. Subject to the actual construction cost, we would purchase our interest for between $22.0 and $25.5 million in the first quarter of 2008, when the new pipeline system is expected to become fully operational. The pipeline is being built to 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, which is currently flowing on Plains’ Rocky Mountain Pipeline. Our investment in the project is subject to various conditions, including the negotiation and execution of mutually satisfactory definitive agreements.

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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.”

Item 9B. Other Information

There have been no events that occurred in the fourth quarter of 2006 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. (“HLS”), 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. 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, recommends engagement of 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 of the three independent directors which oversees compensation decisions for the officers of HLS, as well as 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 atpresiding.director@hollyenergypartners.com or write to: Charles M. Darling, IV, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 100 Crescent Court, Dallas, Texas 75201-6915.

The board of directors of HLS held seven meetings during 2006, with the audit committee, conflicts committee and compensation committee holding seven, five and four meetings, respectively. All board members attended each board meeting, with the exception of Mr. Norsworthy, who attended five meetings. 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. Mr. Blair spends all of his time in the management of our business. Mr. Townsend spends approximately 60% of his time managing the operational aspects of our business. Mr. Ridenour spends approximately half his time overseeing our accounting activities and in corporate development. The rest of our officers devote approximately one-quarter of their time to us. Our non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

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The following table shows information for the current directors and executive officers of HLS.

Name	Age		Position with HLS
Matthew P. Clifton		55	Chairman of the Board and Chief Executive Officer1
P. Dean Ridenour		65	Director, Vice President and Chief Accounting Officer1
Stephen J. McDonnell		55	Vice President and Chief Financial Officer
W. John Glancy		64	Vice President and General Counsel
David G. Blair		48	Senior Vice President
James G. Townsend		52	Vice President — Pipeline Operations
Lamar Norsworthy		60	Director
Charles M. Darling, IV		58	Director234
Jerry W. Pinkerton		66	Director1234
William P. Stengel		58	Director234

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. Cliftonwas 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 Corporation from 1991 to 1995, President of Navajo Pipeline Company, a wholly owned subsidiary of Holly Corporation, since its inception in 1981, President of Holly Corporation from 1995 to 2005, and has served as Chief Executive Officer of Holly Corporation since January 1, 2006. Mr. Clifton has also served as a director of Holly Corporation since 1995.

P. Dean Ridenourwas elected to our Board of Directors in August 2004 and to the position of Vice President and Chief Accounting Officer in January 2005. Mr. Ridenour has served as Vice President and Chief Accounting Officer of Holly Corporation since December 2004. Beginning in October 2002, Mr. Ridenour began providing full-time consulting services to Holly Corporation, and in August 2004, Mr. Ridenour became a full-time employee and officer of Holly Corporation in the position of Vice President, Special Projects, serving in that position until December 2004. 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.

Stephen J. McDonnellwas elected Vice President and Chief Financial Officer in March 2004. Mr. McDonnell held the office of Vice President, Finance and Corporate Development of Holly Corporation from August 2000 to September 2001, when he became the Vice President and Chief Financial Officer of Holly Corporation. Mr. McDonnell was previously employed with Central and South West Corporation as Vice President in the mergers and acquisitions area from 1996 to June 2000. Mr. McDonnell joined Central and South West in 1977 as Manager of Financial Reporting. Mr. McDonnell held a number of accounting and finance positions with Central and South West, including the position of Corporate Treasurer from 1989 to 1996.

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W. John Glancywas elected Vice President and General Counsel in August 2004, and served as Secretary from August 2004 to April 2005. Mr. Glancy has served as Senior Vice President and General Counsel of Holly Corporation since September 1999. From December 1998 to September 1999, he was Senior Vice President—Legal of Holly Corporation and held the office of Secretary of Holly Corporation from April 1999 until February 2005. From 1997 through March 1999, he practiced law in the Law Offices of W. John Glancy in Dallas. From 1972 through 1996, he was in private law practice with several different law firms in Dallas. He also was a director of Holly Corporation from 1975 to 1995, and for part of that period was Secretary of Holly Corporation.

David G. Blairwas elected Senior Vice President in January 2007. He has been employed by Holly for over 25 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.

James G. Townsendwas elected Vice President — Pipeline Operations in March 2004. He has been Vice President of Pipelines and Terminals for Holly Corporation since 1997. Mr. Townsend served as Manager of Transportation for Navajo Refining Company, a wholly-owned subsidiary of Holly Corporation, from 1995 to 1997. Mr. Townsend has worked in Navajo Refining’s pipeline group since joining Navajo Refining in 1984.

Lamar Norsworthywas elected to our Board of Directors in March 2004. He joined Holly Corporation in 1967, was elected to the Board of Directors in 1968 and has been Chairman of the Board since 1977. He served as Chief Executive Officer of Holly Corporation from 1971 to 2005. Mr. Norsworthy is also a Director of Cooper Cameron Corporation, a publicly traded manufacturer of oil field services equipment.

Charles M. Darling, IVwas 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.

Jerry W. Pinkertonwas 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., an energy services company, with respect to accounting-related projects principally involving financial reporting. 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/Lone Star Gas Company, a diversified energy company. 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.

William P. Stengelwas 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. and was responsible for Citigroup’s global relationships with U.S. multinational oil and gas companies headquartered in the United States. From 1973 to 1997, Mr. Stengel served in various other capacities with Citigroup/Citibank, N.A.

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Compliance With Section 16(a) of the Securities Exchange Act of 1934

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10% of Holly Energy Partners, L.P.’s units to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of Holly Energy Partners, L.P.’s equity securities. Holly Energy Partners, L.P. believes that during the year ended December 31, 2006, its officers, directors and 10% unitholders were in compliance with applicable requirements of Section 16(a).

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.

The audit committee selects HEP’s 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 being performed by the independent auditor and its compatibility with their continued objectivity and independence.

Report of the Audit Committee for the Year Ended December 31, 2006

Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.’s internal controls and the financial reporting process. Ernst & Young LLP, Holly Energy Partners, L.P.’s Independent Registered Public Accounting Firm for the year ended December 31, 2006, 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 both management’s assessment of and 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 selects Holly Energy Partners, L.P.’s independent registered public accounting firm.

The audit committee has reviewed and discussed Holly Energy Partners, L.P.’s audited consolidated financial statements with management and the independent registered public accounting firm. The audit committee has discussed with Ernst & Young LLP the matters required to be discussed by Statement on Auditing Standards No. 61, “Communications with Audit Committees.”The audit committee has received the written disclosures and the letter from Ernst & Young LLP required by Independence Standards Board Standard No. 1,“Independence Discussions with Audit Committees,” and has discussed with Ernst & Young LLP that firm’s independence.

The audit committee selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the Partnership for the 2006 calendar year.

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 atwww.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 services reported in the audit, audit-related, tax and all other fees categories above were approved by the audit committee.

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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, 2006.

Members of the Audit Committee:
Jerry W. Pinkerton, Chairman
Charles M. Darling, IV
William P. Stengel

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 atwww.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 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 2006, 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

Retainers and Fees

Officers or employees of HLS who also serve as directors do not receive additional compensation. The only officers of HLS who also serve as directors are Messrs. Clifton and Ridenour. In August 2006, the Board of Directors implemented changes to the cash and equity components of the compensation of non-employee directors. For the year ended December 31, 2006, directors who are not officers or employees of HLS or Holly are currently compensated by: (a) a $30,000 annual cash retainer, payable in four quarterly installments (adjusted from $25,000 in 2005); (b) $1,500 for attendance at each in-person meeting of the Board of Directors or a Board committee, a $1,500 meeting fee for attendance at each telephone meeting of the Board of Directors or a Board committee that lasts more than two hours and a $750 meeting fee for attendance at each telephone meeting of the Board of Directors or a Board committee that lasts from one-half hour up to two hours (adjusted from $1,500 for every meeting, with a maximum of one committee meeting per day in 2005); (c) an annual grant of restricted units equal in value to $40,000 on the date of grant, with a vesting period of one year (adjusted from $40,000 with a vesting period of three years in 2005). In addition, the directors who serve as chairpersons of the Audit and Conflicts Committees each receive an annual retainer of $7,500 (adjusted from $5,000 in 2005). The director who serves as chairperson of the Compensation Committee receives an annual retainer of $5,000 (no change). In addition, each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Each of the directors who are not officers or employees of HLS or Holly each received total cash compensation for the annual retainer and for board and committee meetings totaling $61,500 in 2005.

Equity-Based Compensation

Non-employee directors are annually awarded restricted HEP units under the Holly Energy Partners, L.P. Long-Term Incentive Plan (the “Long-Term Incentive Plan”). A restricted HEP unit is a common unit subject to forfeiture prior to the vesting of the award.

During the period ended December 31, 2006, compensation was made to directors of HLS as set forth below:

	Fees Earned or		Stock		All Other
	Paid in Cash		Awards(1)		Compensation		Total
Charles M. Darling, IV	$	67,750	$	46,246	$	7,016	$	121,012
Jerry W. Pinkerton	$	69,000	$	46,246	$	7,016	$	122,262
William P. Stengel	$	69,000	$	46,246	$	7,016	$	122,262

(1) Reflects the amount recognized in the year ended December 31, 2006 in accordance with SFAS 123(r), and includes amounts for awards granted prior to 2006. In 2006, each of the directors listed received an award of 1,070 restricted HEP units with a grant date fair value of $40,018. The restricted HEP units will vest on August 1, 2007. The fair value of each restricted unit grant is measured on the grant date and is amortized over the vesting period. As of December 31, 2006, Messrs. Darling, Pinkerton and Stengel each held 3,509 unvested restricted units.

COMPENSATION DISCUSSION AND ANALYSIS

This compensation discussion and analysis (“CD&A”) is intended to provide information about our compensation objectives and policies for our principal executive officer, our principal financial officer and our other most highly compensated executive officers that will place in perspective the information

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contained in the tables that follow this discussion. Our CD&A begins with a description of our relationship with Holly with respect to reimbursement of compensation expenses and is followed by a general description of our compensation program and specific information as to its various components. Immediately following the CD&A is the Compensation Committee Report (the “Committee Report”). Following the Committee Report are compensation tables describing compensation paid in 2006 and outstanding equity awards held by executives. At the end, we have provided information concerning pension benefits and change-in-control agreements.

Overview

HEP has no employees. HEP is managed through HLS, the general partner of HEP’s general partner. The board of directors and employees providing services to HEP are retained by HLS. HLS is a subsidiary of Holly and currently has 89 employees that provide general, administrative and operational services to HEP. Throughout this discussion, the individuals included in the Summary Compensation Table on page 97, who are Matthew P. Clifton, HLS’s Chairman of the Board and Chief Executive Officer, Stephen J. McDonnell, HLS’s Vice President and Chief Financial Officer, P. Dean Ridenour, HLS’s Vice President and Chief Accounting Officer, and James G. Townsend, Vice President - - Pipeline Operations, are referred to as the “Named Executive Officers.” Although HLS has additional executive officers, none of the additional executive officers of HLS received total compensation from HLS in 2006 in excess of $100,000.

Under the terms of the Omnibus Agreement, we pay Holly an annual administrative fee in the amount of $2.0 million 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. These expenses include the costs of employee, officer, and director compensation and benefits properly allocable to HEP and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, HEP. The partnership agreement provides that the 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 relationships and transactions we have with Holly. Each of the services included within the administrative fee is not assigned any particular individual value. Further, no portion of the administrative fee is subject to an allocation agreement for the services provided by the individual Named Executive Officers of HLS. Consequently, the compensation paid by Holly to the Named Executive Officers is not allocable to the annual administrative fee as reimbursement of compensation paid by Holly for services performed by the Named Executive Officers for HLS.

Other than as generally covered by the administrative fee, no expense associated with the compensation paid by Holly or HLS to the Named Executive Officers of HLS other than to Mr. Townsend is charged to or reimbursed by HEP. The only exception is with respect to equity compensation paid by HEP to the Named Executive Officers. In that case, HLS purchases the units, and HEP reimburses HLS for the purchase price.

We reimburse HLS for 58% of the expenses incurred by HLS to pay Mr. Townsend’s salary, bonus, retirement and other benefits. As Mr. Townsend also provides services to Holly’s subsidiary, Navajo Pipeline Co., L.P. (“Navajo Pipeline”), 42% of his cash compensation and benefits are charged to Navajo Pipeline. We reimburse HLS for 100% of the expenses incurred in providing Mr. Townsend with long-term incentive equity compensation. All compensation paid to him by Holly is fully disclosed in the tabular disclosure following this compensation discussion and analysis. Messrs. Clifton, McDonnell and Ridenour are 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 compensation paid to Messrs. Clifton, McDonnell and Ridenour by Holly is properly allocable to the services provided by Messrs. Clifton, McDonnell and Ridenour to HLS and, therefore, only the Long-Term Incentive Plan awards granted to them are disclosed herein.

With respect to Mr. Townsend, we use a compensation approach that includes a mix of base salary, goal-driven annual cash bonus awards with target amounts expressed as percentages of salary, and annual long-term incentive awards consisting of restricted units of HEP. In addition, Mr. Townsend is provided

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with benefits that are generally available to all of Holly’s salaried employees, as described more fully below.

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 tie compensation to business and individual performance and to provide total compensation competitive with our peers. Our compensation levels are reviewed in light of publicly available information on compensation paid by companies in our industry that are similar to us, taking into account HEP’s size.

The HLS Compensation Committee (the “Committee”), comprised entirely of independent directors, administers our compensation program. The Committee determines and approves, upon the recommendation of management, the equity compensation to be paid to the Named Executive Officers and the compensation in addition to equity compensation to Mr. Townsend.

The Committee has not adopted any formal policies for allocating compensation among salaries, bonuses and equity compensation. However, in the case of Mr. Townsend, the Committee, with the assistance of management, seeks to designate an appropriate mix of cash and long-term equity incentive compensation with a goal of providing compensation to retain Mr. Townsend, while providing incentives to maximize long-term value for HEP and its unitholders. The Committee, with the assistance of management, annually performs an internal review of each of the other Named Executive Officers’ equity compensation to determine whether the executives are being provided with equity awards that are effective in motivating the Named Executive Officers to continue to create long-term value for HEP. The Committee also compares the Named Executive Officers’ compensation to that of comparable executives in other similarly situated businesses. Because Messrs. Clifton, McDonnell and Ridenour only commit less than half of their business time to HEP, during which time they are primarily involved in determining the long-term business goals and policies of HEP, the Committee believes that it is appropriate to compensate them only through long-term incentives to retain them during the period of time during which their policies are expected to impact our business and that will reward them in accordance with the success of those long-term goals and policies.

As part of its consideration, the Committee reviews and discusses market data and recommendations provided by an established, independent consulting firm specializing in executive compensation issues. Except with respect to his own compensation, the Committee solicits the recommendations of our Chairman of the Board and Chief Executive Officer, which the Committee considers in making its determinations.

Overview of 2006 Executive Compensation Components

For Mr. Townsend, the components of compensation in 2006 were:

• base salary;

• annual performance-based cash incentive compensation;

• long-term equity incentive compensation; and

• retirement and other benefits.

The Committee also reviewed the total compensation provided to Mr. Townsend in the previous year in determining compensation to be paid in 2006.

In 2006, the only component of compensation we provided for the other Named Executive Officers was long-term equity incentive compensation. All Named Executive Officers receiving equity awards received restricted units, with the exception of Mr. Clifton, who received an award of performance units. The nature of each of these types of awards is more fully described below.

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Base Salary

Base salary for Mr. Townsend was approved in January 2006 by the Committee based on his position and level of responsibility, individual performance, HLS’s salary range for executives at his level and market practices. The Committee also reviewed competitive market data provided by an independent consultant relevant to his position. After reviewing Mr. Townsend’s responsibilities, contributions to HEP’s long-term value and the competitive market data, the Committee approved Mr. Townsend’s salary for 2006 at $190,000.

Annual Incentive Cash Bonus Compensation

The Holly Logistic Services Annual Incentive Plan (the “Annual Incentive Plan”) was adopted by the HLS Board of Directors in August 2004 with the objective of motivating management and the employees of HLS and its affiliates who perform services for HLS and HEP to collectively produce outstanding results, encourage superior performance, increase productivity, and aid in attracting and retaining key employees. The Committee oversees the administration of the Annual Incentive Plan, and any potential awards granted pursuant to it are subject to final determination by the Committee that the performance goals for the applicable periods have been achieved.

Payment with respect to any cash bonus is contingent upon the satisfaction of the pre-established objective and subjective performance criteria described in note (3) to the Summary Compensation Table below. These performance criteria include both HEP and Holly factors, given the scope of responsibilities of our named executive officers. The total bonus pool for all executives and employees of HLS is typically determined by the Committee after the end of each year or designated performance period. At such time, the Committee also approves the granting of new awards for the current year or designated performance period. Awards for a given year are paid in cash in the first quarter of the following year.

Early in each new year, the Committee approves the performance measures and performance targets to be used for the upcoming calendar year in determining the cash bonus amounts to be paid pursuant to the Annual Incentive Plan. Under the Annual Incentive Plan, performance targets may be based on any factors as the Chairman of the Board and Chief Executive Officer, subject to the approval of the Committee, may determine.

Mr. Townsend’s target bonus amount for 2006 was approved by the Committee as a percentage of his base salary equal to 40%. Under the pre-defined performance goals described below in the narrative accompanying the Summary Compensation Table, Mr. Townsend was eligible to receive up to 200% of his target bonus amount (equal to 80% of his base salary).

In addition to the pre-defined performance criteria, the Committee has discretion to approve an increase or decrease in a Named Executive Officer’s bonus. In making the determination as to whether such discretion should be applied, the Committee reviews the recommendations from management. For 2006, the Committee determined to approve a discretionary increase in Mr. Townsend’s bonus. Mr. Townsend’s 2006 bonus will be paid in March 2007.

Long-Term Incentive Equity Compensation

The Long-Term Incentive Plan was adopted by the HLS Board of Directors in August 2004 with the objective of promoting the interests of HEP by providing to management, employees and consultants of HLS and its affiliates who perform services for HLS and HEP and its subsidiaries incentive compensation awards that are based on units of HEP. The Long-Term Incentive Plan is also contemplated to enhance our ability to attract and retain the services of individuals who are essential for the growth and profitability of HEP and to encourage them to devote their best efforts to advancing our business. The Long-Term Incentive Plan is administered by the Committee.

The Long-Term Incentive Plan contemplates four potential types of awards: restricted units, phantom units, unit options and unit appreciation rights. Since the inception of HEP, we have awarded only restricted units and phantom units, the latter being referred to herein as performance unit awards.

With respect to the Named Executive Officers, in determining the appropriate amount and type of long-term incentive awards to be made, the Committee considers the amount of time devoted by each

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executive to our business, the executive’s scope of responsibility, base salary and available compensation information for executives in comparable positions in similar companies.

Restricted Units

A restricted unit is a common unit subject to forfeiture upon termination of employment prior to the vesting of the award. The Committee may approve grants on the terms that it determines, including the period during which the award will vest. Under the Long-Term Incentive Plan, the Committee may condition vesting upon the achievement of specified financial objectives. The restricted units will vest upon a change of control of HEP, our general partner, HLS or Holly, unless provided otherwise by the Committee. Restricted unit holders have all the rights of a unitholder with respect to such restricted units, including the right to receive all distributions paid with respect to such restricted units and any right to vote with respect to the restricted units, subject to limitations on transfer and disposition of the units during the restricted period.

In 2006, the Named Executive Officers who were granted awards of restricted units were Messrs. McDonnell, Ridenour and Townsend. One-third of these restricted unit awards became fully vested and nonforfeitable on January 2, 2007. After December 31, 2007, two-thirds of the restricted units will be fully vested and nonforfeitable, and all the restricted units will be fully vested and nonforfeitable after December 31, 2008.

Phantom Units and Performance Units

A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, as may be provided in the applicable agreement between the grantee and HLS, the cash equivalent to the value of a common unit. A performance unit is a phantom unit that will only be settled upon the attainment of pre-established performance targets. The Committee may approve grants on such terms as the Committee shall determine. The Committee approves the period over which phantom units will vest, and the Committee may base its determination upon the achievement of specified financial objectives. As with restricted units, phantom units will vest upon a change of control of HEP, our general partner, HLS or Holly, unless provided otherwise by the Committee. Phantom units are also subject to forfeiture in the event that the executive’s employment or service relationship terminates for any reason, unless and to the extent that the Committee provides otherwise.

In 2006, the only Named Executive Officer who received an award of performance units was Mr. Clifton. Performance units were awarded to Mr. Clifton given his responsibilities to HEP with respect to long-term strategy. The performance period for such award is from January 1, 2006 through December 31, 2008. Mr. Clifton may earn no less than 50% and no more than 150% of the performance units subject to his award over the course of the performance period as described more fully in the narrative accompanying the Grant of Plan Based Awards Table. Mr. Clifton’s performance units may be settled only in common units of HEP.

Acquisition of Common Units for Long-Term Incentive Equity Awards

Common units to be delivered in connection with the grant of performance unit awards may be common units acquired by HLS on the open market, common units already owned by HLS, common units acquired by HLS directly from us or any other person or any combination of the foregoing. We do not currently hold treasury units. HLS is entitled to reimbursement by us for the cost of acquiring the common units.

Review of Peer Data

Market pay levels are one of many factors we consider in setting compensation for the Named Executive Officers. To provide a frame of reference in evaluating the reasonableness and competitiveness of compensation, market pay levels are obtained from various sources including published compensation surveys and information taken from the SEC filings for a number of publicly traded master limited partnerships (“MLPs”). The MLP benchmark group that the Committee reviewed with management and its outside consultant was comprised of: Kinder Morgan Energy Partners,

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L.P., Enbridge Energy Partners, L.P., TEPPCO Partners, L.P., Valero L.P., Magellan Midstream Partners, L.P., Buckeye Energy Partners, L.P. and Sunoco Logistics Partners L.P., Pacific Energy Partners, L.P. (which merged with Plains All American Pipeline on November 15, 2006), Inergy L.P., Crosstex Energy, LP, TC Pipelines, LP, Mark West Energy Partners, L.P., Atlas Pipeline Partners, L.P. and Hiland Partners, LP. Our objective is to position pay levels approximating the middle range of market practice. As noted, however, market pay levels are only one factor considered, with pay decisions ultimately reflecting an evaluation of individual contribution and value to HEP.

Role of Named Executive Officers in Determining Executive Compensation

Various members of management facilitate the Committee’s consideration of compensation for Named Executive Officers by providing data for the Committee’s review. This data includes, but is not limited to HEP’s annual budget as approved by HLS’s Board of Directors, HEP’s financial performance over the course of the year versus that of its peers, performance evaluations of Named Executive Officers, compensation provided to the Named Executive Officers in previous years, tax-related considerations and accounting-related considerations. Management provides the Committee with guidance as to how such data impacts pre-determined performance goals set by the Committee during the previous year. When management considers a discretionary bonus to be appropriate for a Named Executive Officer, it will suggest an amount and provide the Committee with management’s rationale for such bonus. Given the day-to-day familiarity that management has with the work performed by the Named Executive Officers, the Committee values management’s recommendations. However, the Committee makes the final decision as to the compensation of HLS’s Named Executive Officers.

Tax and Accounting Implications

We account for the equity compensation expense for our employees and executive officers, including our Named Executive Officers, under the rules of SFAS 123(r), which requires us to estimate and record an expense for each award of equity compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued. As HLS is a subsidiary of a publicly-traded corporation, the Committee is mindful of the impact that Section 162(m) of the Internal Revenue Code (the “Code”) may have on compensatory deductions passed through to HLS’s parent. To the extent Section 162(m) of the Code may ever impact the deductibility of such arrangements, the Committee intends generally to structure arrangements, where feasible, so as to minimize or eliminate the impact of the limitations of Section 162(m) of the Code. Nevertheless, to the extent that, in the opinion of the Committee, structuring compensatory arrangements to fully maximize a corporate deduction is not in the best interest of HEP, either due to the need to attract or retain top talent or for any other legitimate business reason, the Committee may approve compensation arrangements that are not deductible or not fully deductible.

Retirement and Benefit Plans

The cost of benefits for employees of HLS are charged monthly to us by Holly in accordance with the terms of the Omnibus Agreement. These employees participate in the available retirement and thrift plans of Holly. Holly’s tax qualified defined benefit retirement plan is described below in the narrative accompanying the Pension Benefits Table.

The Thrift Plan is offered to all employees of HLS, which plan is qualified under the Code. In 2006, employees had the option to participate in both the Retirement Plan and the Thrift Plan. Employees were permitted to make contributions to the Thrift Plan of 1% to 50% of their compensation. In 2006, for non-bargained employees who had at least one year of service, Holly matched employee contributions to the Thrift Plan up to 4% of their compensation. Employee contributions that were made on a tax-deferred basis were generally limited to $15,000 per year with employees over 50 years of age able to make additional tax-deferred contributions of $5,000. Prior to 2007, Holly’s contributions in the Thrift Plan did not vest until the earlier of three years of credited service or termination of employment due to retirement, disability or death.

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Mr. Townsend is the only Named Executive Officer whose Retirement Plan and Thrift Plan benefits are charged to us by Holly.

Change-in-Control Agreements

On February 9, 2007, the Board of Directors of Holly approved Change-in-Control Agreements to be entered into with Mr. Townsend and David G. Blair. Mr. Blair was elected as HLS’s Senior Vice President effective January 1, 2007 and beginning in 2007 is a named executive officer of HLS. The expenses associated with the Change-in-Control Agreements are not reimbursable to Holly by us.

The Change-in-Control Agreements will provide that if in connection with or within two years after a “change in control” of Holly, HLS or HEP (1) the executive is terminated without “cause,” leaves voluntarily “for good reason,” or is terminated as a condition of the occurrence of the transaction constituting the “change in control,” and (2) the executive is not offered employment with Holly or its related entities on substantially the same terms as his previous employment with HLS within 30 days after such termination, then the executive will receive the following cash severance amounts paid by Holly, and not reimbursable by HEP as outlined in the table below: (i) a cash payment equal to his accrued and unpaid salary, reimbursement of expenses and accrued vacation pay, and (ii) a lump sum amount equal to a multiple specified in the table below for such executive times (A) his annual base salary as of his date of termination or the date immediately prior to the “change in control,” whichever is greater, and (B) his annual bonus amount, calculated as the average annual bonus paid to him for the prior three years. In addition, the executive (and his dependents, as applicable) will receive a continuation of their medical and dental benefits for the number of years indicated in the table below for such executive. All payments and benefits due under the agreements will be conditioned on execution and nonrevocation by the executive of a release for the benefit of Holly, HLS and HEP and their related entities and agents. If amounts payable to an executive under the agreement (or pursuant to any other arrangement or agreement with Holly, HLS or HEP that are payable as a result of a change in ownership or control) (collectively, the “Payments”) exceed the amount allowed under section 280G of the Internal Revenue Code of 1986, as amended (the “Code”), for such executive by 10% or more, Holly will pay the executive a tax gross up (a “Gross Up”) in an amount necessary to allow the executive to retain (after all regular income and Code Section 280G taxes) a net amount equal to the total present value of the Payments on the date they are to be paid (after all regular income taxes but without reduction for Code Section 290G taxes). Conversely, the Payments will be cut back if they exceed the Code section 280G limit for the executive by less than 10%.

	Cash Severance	Years for Continuation of
Named Executive Officer	Multiple	Medical and Dental Benefits
David G. Blair	2 times		2
James G. Townsend	1 times		1

Compensation Committee Report

The Compensation Committee of the Holly Logistic Services, L.L.C. Board of Directors has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.

Members of the Compensation Committee:
Charles M. Darling, IV, Chairman
Jerry W. Pinkerton
William P. Stengel

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Summary Compensation Table

The table below summarizes the total compensation paid or earned by each of the Named Executive Officers in 2006. Neither we nor HLS has entered into any employment agreements with any of the Named Executive Officers, other than the change-in-control agreements described above. As previously noted, the cash compensation and benefits for Named Executive Officers other than Mr. Townsend were neither paid by us nor allocable to services those Named Executive Officers performed for us in 2006. Information regarding the compensation paid to Messrs. Clifton, McDonnell and Ridenour as consideration for the services they perform for Holly will be reported in Holly’s annual proxy statement.

Summary Compensation Table
														Non-Equity			Change in
														Incentive Plan			Pension			All Other
Name and			Salary			Bonus			Stock Awards			Option Awards		Compensation			Value			Compensation			Total
Principal Position	Year		($)			($)			($)			($)		($)			($)			($)			($)
Matthew P. Clifton, Chairman of the Board and Chief Executive Officer		2006	$	—		$	—		$	193,784	(1)	$	—	$	—		$	—		$	—		$	193,784
Stephen J. McDonnell, Vice President and Chief Financial Officer		2006	$	—		$	—		$	29,084	(1)	$	—	$	—		$	—		$	—		$	29,084
P. Dean Ridenour, Vice President and Chief Accounting Officer		2006	$	—		$	—		$	101,793	(1)	$	—	$	—		$	—		$	—		$	101,793
James G. Townsend, Vice President — Pipeline Operations		2006	$	203,940	(2)	$	30,000	(3)	$	58,168	(1)	$	—	$	143,000	(4)	$	38,555	(5)	$	7,471	(6)	$	481,134

(1)	See our note 6 to consolidated financial statements for a discussion of the assumptions used in determining the SFAS 123(r) compensation cost of these awards. The amount for Mr. Clifton is based on an estimated payment of 125% of the performance units.
(2)	Mr. Townsend’s annual salary was adjusted to $190,000 effective March 1, 2006 from his previous salary of $175,398. The $203,940 is comprised of: (i) ten months of salary at the March 1, 2006 rate, (ii) two months of salary at the previous rate, and (iii) an adjustment of $17,160 to correct for a raise approved in 2005 not reflected in his previous annual salary. 42% of Mr. Townsend’s salary was charged to Navajo Pipeline for services provided in 2006 by Mr. Townsend to Navajo Pipeline.
(3)	This reflects the discretionary portion of Mr. Townsend’s bonus, which amount is in excess of the pre-defined target amount. 42% of this amount was charged to Navajo Pipeline for services provided in 2006 by Mr. Townsend to Navajo Pipeline.
(4)	This reflects the pre-defined target percentages that were allocated to various components as follows:

• A portion of Mr. Townsend’s bonus equal to 5% of his base salary, based on Holly’s pre-tax net income (“PTNI”) goal of $197,907,000. This component was subject to being adjusted to a minimum amount of 0% and a maximum amount of 10%. As Holly exceeded its PTNI goal by 20%, this component was earned at 10%.

• A portion of Mr. Townsend’s bonus equal to 5% of his base salary, based on Holly’s stock price performance over the year versus that of its peers. This component was subject to

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being adjusted to a minimum amount of 0% and a maximum amount of 10%. As Holly outperformed its peers, this component was earned at 10%.

• A portion of Mr. Townsend’s bonus equal to 20% of his base salary, based on the performance of Mr. Townsend’s business unit versus the unit’s budgeted goal for 2006. Given the performance of the business unit versus its internal goals for 2006, this component was earned at 40%.

• A portion of Mr. Townsend’s bonus equal to 10% of his base salary, based on Mr. Townsend’s individual performance over the year. This component was subject to being adjusted to a minimum amount of 0% and a maximum amount of 20%. Mr. Townsend’s individual performance for 2006 was evaluated through an annual performance review completed in February 2007. The review included a written assessment provided by Mr. Townsend’s immediate supervisor. The assessment reviewed how well Mr. Townsend displayed each of the following six “Performance Dimensions”:

- Interpersonal Effectiveness

- Business Conduct

- Leadership

- Professional & Technical Competency

- Results Orientation

- Strengths

Each one of these performance dimensions had a variety of sub-categories that were separately reviewed. The assessment also evaluated how well Mr. Townsend had performed the individual goals he had been assigned for 2006. As a result of the assessment, Mr. Townsend was eligible to receive as part of his bonus 15% of his base salary.

(5) This reflects the following assumptions:

	December 31, 2005	December 31, 2006
Discount Rate:	5.75%	6.00%
Mortality Table:	1994 Group Annuity	RP2000 White Collar
Reserving Table:	Projected to 2020	(50% Male/ 50% Female)
Retirement Age:	62	62

(6) This reflects matching contributions made to the Thrift Plan by HLS, which was reimbursed by HEP.

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2006 Grants of Plan-Based Awards

Estimated Future Payouts Under

Estimated Future Payouts

Non-Equity Incentive Plan

Under Equity Incentive Plan

Awards

Awards

(c)

(b)

Thresh

(d)

(e)

(f)

(g)

(h)

All other

Base Price

(j)

(a)

Grant

-old

Target

Maximum

Thresh-old

Target

Maximum

Equity

of Awards

Grant Date

Name

Date

($)

($)

($)

(#)

(#)

(#)

Awards

($/Unit) (i)

Fair Value

Matthew P. Clifton, Chairman of the Board and Chief Executive Officer

2/16/2006

n/a

n/a

n/a

4,219

(1)

8,438

(1)

12,657

(1)

n/a

n/a

$

416,099

(7)

Stephen J. McDonnell, Vice President and Chief Financial Officer

2/16/2006

n/a

n/a

n/a

n/a

n/a

n/a

1,250

(2)

n/a

$

49,313

(8)

P. Dean Ridenour, Vice President and Chief Accounting Officer

2/16/2006

n/a

n/a

n/a

n/a

n/a

n/a

4,375

(3)

n/a

$

172,594

(8)

James G. Townsend, Vice President — Pipeline Operations

2/16/2006

n/a

$

76,000

(4)

$

152,000

(5)

n/a

n/a

n/a

2,500

(6)

n/a

$

98,625

(8)

(1) The Committee approved a grant of 8,438 performance units to Mr. Clifton. Under the terms of the grant, Mr. Clifton may earn from 50% to 150% of the performance units, based on the increase in HEP’s cash distributions on the common units of HEP. The performance period for the award began on January 1, 2006 and ends on December 31, 2008. Following the completion of the performance period, Mr. Clifton shall be entitled to a payment of a number of common units equal to the result of multiplying the original grant amount of 8,438 by the performance percentage set forth below:

3-Year Total Increase in Cash	Performance
Distributions Per Common Unit	Percentage (%) to be
above $7.50 (beginning with	Multiplied
base of $2.50)	by Performance Units
$0.00 or less	50%
$0.62	100%
$1.27 or more	150%

In order to receive 100% of the units subject to this award, the cash distributions per unit declared and paid in the three years ended December 31, 2008 must total $8.12 per unit. In order to receive 125%, the distributions per unit declared and paid for the three years ended December 31, 2008 must total $8.44 per unit. In order to receive 150%, the distributions per unit declared and paid in the three years ended December 31, 2008 must total $8.77 per unit. The percentages shall be interpolated between points.

In the event that Mr. Clifton’s employment terminates prior to January 1, 2009, other than due to a defined change-in-control event, death, disability or retirement, he will forfeit his award. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. Clifton’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. Clifton shall forfeit a number of units equal to the percentage that the number of full months following the date of separation, death, disability or retirement to the end of the performance period bears to 36. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may make a payment assuming a performance percentage of up to 150% instead of the prorated number. As outlined above, the amount shown in column (f) reflects the minimum payment amount of 50%, the amount shown in column (g) reflects the target amount of 100% and the amount shown in column (h) reflects the maximum payment level of 150%.

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(2)	The Committee approved a grant of 1,250 restricted units to Mr. McDonnell. Under the terms of the grant, 1/3 of the restricted units were fully vested and nonforfeitable after December 31, 2006, 2/3 will be fully vested and nonforfeitable after December 31, 2007, and all of the restricted units will be fully vested and nonforfeitable after December 31, 2008. Other than due to a defined change-in-control event, death, disability or retirement, Mr. McDonnell shall forfeit the remaining units if his employment is terminated after December 31, 2006 and before January 1, 2008, and one-third of the units if his employment is terminated after December 31, 2007 and before January 1, 2009. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. McDonnell’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. McDonnell shall forfeit a number of units equal to (i) the total award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2008 bears to 36. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. McDonnell is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.
(3)	The Committee approved a grant of 4,375 restricted units to Mr. Ridenour. Under the terms of the grant, 1/3 of the restricted units were fully vested and nonforfeitable after December 31, 2006, 2/3 will be fully vested and nonforfeitable after December 31, 2007, and all of the restricted units will be fully vested and nonforfeitable after December 31, 2008. Other than due to a defined change-in-control event, death, disability or retirement, Mr. Ridenour shall forfeit the remaining units if his employment is terminated after December 31, 2006 and before January 1, 2008, and one-third of the units if his employment is terminated after December 31, 2007 and before January 1, 2009. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. Ridenour’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. Ridenour shall forfeit a number of units equal to (i) the total award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2008 bears to 36. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. Ridenour is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.
(4)	This reflects a target bonus award amount for Mr. Townsend equal to 40% of his 2006 salary.
(5)	This reflects that Mr. Townsend may receive up to 200% of the target bonus award amount.
(6)	The Committee approved a grant of 2,500 restricted units to Mr. Townsend. Under the terms of the grant, 1/3 of the restricted units were fully vested and nonforfeitable after December 31, 2006, 2/3 will be fully vested and nonforfeitable after December 31, 2007, and all of the restricted units will be fully vested and nonforfeitable after December 31, 2008. Other than due to a defined change-in-control event, death, disability or retirement, Mr. Townsend shall forfeit the remaining units if his employment is terminated after December 31, 2006 and before January 1, 2008, and one-third of the units if his employment is terminated after December 31, 2007 and before January 1, 2009. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. Townsend’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. Townsend shall forfeit a number of units equal to (i) the total award times (ii)

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	the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2008 bears to 36. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. Townsend is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.
(7)	This reflects the closing price at the date of grant and an assumed payment of 125% of the performance units.
(8)	This reflects the closing price at the date of grant.

Outstanding Equity Awards at Fiscal Year End

	Equity Awards
							Equity Incentive			Equity Incentive Plan
	Number						Plan Awards:			Awards: Market or
	of Units						Number of Unearned			Payout Value of
	That Had			Market Value of			Units, Units or Other			Unearned Units, Units
	Not			Units That Had			Rights That Had Not			or Other Rights That
	Vested			Not Vested			Vested			Had Not Vested
Name	(#)			($)			(#)			($)
Matthew P. Clifton, Chairman of the Board and Chief Executive Officer		n/a			n/a			16,240	(1)	$	653,660
Stephen J. McDonnell, Vice President and Chief Financial Officer		1,755	(2)	$	70,639	(4)		n/a			n/a
P. Dean Ridenour, Vice President and Chief Accounting Officer		7,096	(3)	$	285,614	(4)		n/a			n/a
James G. Townsend, Vice President — Pipeline Operations		3,231	(5)	$	130,048	(4)		n/a			n/a

(1) This number reflects the combined total of A and B below:

A.

An award of 7,802 restricted units made to Mr. Clifton in February 2005. Except in the case of early termination, after December 31, 2007 (i) one third of the restricted units will vest if HEP’s quarterly adjusted net income per diluted unit is not less than $0.56 for any quarter between October 1, 2007 and December 31, 2010; (ii) one third of the restricted units will vest if HEP’s quarterly adjusted net income per diluted unit is not less than $0.56 for any quarter between October 1, 2008 and December 31, 2010; and (iii) one third of the restricted units will vest if HEP’s quarterly adjusted net income per diluted unit is not less than $0.56 for any quarter between October 1, 2009 and December 31, 2010.

Other than due to a defined change-in-control event, death, disability or retirement, Mr. Clifton shall forfeit all of the restricted units if his employment is terminated before January 1, 2008, two-thirds of the units if his employment is terminated after December 31, 2007 and before January 1, 2009, and one-third of the units if his employment is terminated after December 31, 2008 and before January 1, 2010. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. Clifton’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. Clifton shall forfeit a number of units equal to (i) the total award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on

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December 31, 2009 bears to 60. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. Clifton is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.

B. An award of 8,438 performance units made to Mr. Clifton in February 2006, which are described in footnote 1 to the Grants of Plan-Based Awards table above.

(2) This number reflects the combined total of A and B below:

A.	An award of 505 restricted units made to Mr. McDonnell in February 2005. Under the terms of the grant, except in the case of early termination, 1/3 of the restricted units will be fully vested and nonforfeitable after December 31, 2007, 2/3 will be fully vested and nonforfeitable after December 31, 2008, and all of the restricted units will be fully vested and nonforfeitable after December 31, 2009.
	Other than due to a defined change-in-control event, death, disability or retirement, Mr. McDonnell shall forfeit all of the restricted units if his employment is terminated before January 1, 2008, two-thirds of the units if his employment is terminated after December 31, 2007 and before January 1, 2009, and one-third of the units if his employment is terminated after December 31, 2008 and before January 1, 2010. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. McDonnell’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. McDonnell shall forfeit a number of units equal to (i) the total award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2009 bears to 60. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. McDonnell is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.
B.	An award of 1,250 restricted units made to Mr. McDonnell in February 2006, which are described in footnote 2 to the Grants of Plan-Based Awards table above, one-third of which vested after December 31, 2006.

(3) This number reflects the combined total of A, B and C below:

A.

An award of 1,875 restricted units made to Mr. Ridenour in November 2004. Under the terms of the grant, except in the case of early termination, all of the restricted units will be fully vested on August 4, 2007.

Other than due to a defined change-in-control event, death, disability or retirement, Mr. Ridenour shall forfeit all of the restricted units if his employment is terminated before August 4, 2007. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. Ridenour’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. Ridenour shall forfeit a number of units equal to (i) the total award times (ii) the percentage that the number of days from August 4, 2004 to the date of death, disability or retirement bears to 1095 days. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. Ridenour is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.

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B.	An award of 846 restricted units made to Mr. Ridenour in February 2005. Under the terms of the grant, except in the case of early termination, 1/3 of the restricted units will be fully vested and nonforfeitable after December 31, 2007, 2/3 will be fully vested and nonforfeitable after December 31, 2008, and all of the restricted units will be fully vested and nonforfeitable after December 31, 2009.
	Other than due to a defined change-in-control event, death, disability or retirement, Mr. Ridenour shall forfeit all of the restricted units if his employment is terminated before January 1, 2008, two-thirds of the units if his employment is terminated after December 31, 2007 and before January 1, 2009, and one-third of the units if his employment is terminated after December 31, 2008 and before January 1, 2010. The change-in-control provisions of this award are described below under the section titled Severance and Change-in-Control Arrangements. In the event of Mr. Ridenour’s death, total and permanent disability as determined by the Committee in its sole discretion or retirement after attaining age 62 or retirement after attaining an earlier retirement age approved by the Committee in its sole discretion, Mr. Ridenour shall forfeit a number of units equal to (i) the total award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2009 bears to 60. Any remaining units that are not vested will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Mr. Ridenour is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units.
C.	An award of 4,375 restricted units made to Mr. Ridenour in February 2006, which are described in footnote 2 to the Grants of Plan-Based Awards table above, one-third of which vested after December 31, 2006.

(4)	Based upon the closing market price of $40.25 on December 29, 2006.
(5)	This number reflects the combined total of A and B below:

A.

An award of 731 restricted units made to Mr. Townsend in February 2005. Under the terms of the grant, except in the case of early termination, 1/3 of the restricted units will be fully vested and nonforfeitable after December 31, 2007, 2/3 will be fully vested and nonforfeitable after December 31, 2008, and all of the restricted units will be fully vested and nonforfeitable after December 31, 2009.

B.

An award of 2,500 restricted units made to Mr. Townsend in February 2006, which are described in footnote 2 to the Grants of Plan-Based Awards table above, one-third of which vested after December 31, 2006

None of the equity awards previously granted to our Named Executive Officers vested in 2006.

Pension Benefits Table

In 2006, Mr. Townsend was eligible to receive benefits under Holly’s Noncontributory Retirement Plan after one year of service, with service credited from his date of employment. The Retirement Plan provides a defined benefit to participants generally following their retirement. The compensation covered by the Retirement Plan is the average combined annual salary (and any quarterly bonus, if applicable) compensation during the highest consecutive 36-month period of employment for each employee. (An employee’s term of employment was not deemed interrupted for Holly employees who were transitioned to work as HLS employees for HEP). No quarterly bonuses were provided to executives in 2006. Under the Retirement Plan, subject to certain age and length-of-service requirements, employees upon normal retirement are entitled to a life annuity with yearly pension payments equal to 1.6% of average annual base compensation during their highest compensated consecutive 36-month period of employment multiplied by total credited years of service, less 1.5% of primary Social Security benefits multiplied by

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such service years but not to exceed 45% of such benefits. Benefits up to limits set by the Code are funded by Holly’s contributions to the Retirement Plan, with the amounts determined on an actuarial basis. In 2006, the Code limited benefits that could be covered by the Retirement Plan’s assets to $175,000 per year (subject to increases for future years based on price level changes) and limited the compensation that could be taken into account in computing such benefits to $220,000 per year (subject to certain upward adjustments for future years).

Pension Benefits
				Number of Years			Present Value of			Payments During
Name	Plan Name			Credited Service			Accumulated Benefit			Last Fiscal Year
(a)	(b)			(#) (c)			($) (d)			($) (e)
Matthew P. Clifton, Chairman of the Board and Chief Executive Officer		(1	)		(1	)		(1	)		(1	)
Stephen J. McDonnell, Vice President and Chief Financial Officer		(1	)		(1	)		(1	)		(1	)
P. Dean Ridenour, Vice President and Chief Accounting Officer		(1	)		(1	)		(1	)		(1	)
James G. Townsend , Vice President — Pipeline Operations (2)	Retirement Plan				22.16		$	345,525			—

(1)	We do not reimburse HLS for pension benefits for Messrs. Clifton, McDonnell or Ridenour. Their retirement benefits are paid for by Holly.
(2)	Since Mr. Townsend is over age 50 and has more than 10 years of service, he is eligible for early retirement in the Holly Retirement Plan on December 31, 2006. His early retirement benefit payable beginning January 1, 2007 is estimated to be $2,373 per month payable for his lifetime or $450,250 payable as a lump sum.

	December 31, 2006
Discount Rate	6.00%
Mortality Table	RP2000 White Collar Projected to 2020
	(50% male/ 50% female)
Retirement Age	62

Our Named Executive Officers do not participate in any nonqualified deferred compensation plans.

Severance and Change-in-Control Arrangements

Under the terms of the long-term incentive equity awards described above, if, in the event of a Change in Control (as defined in the applicable award agreements), (i) a Named Executive Officer’s employment is terminated, other than for cause, or (ii) he resigns after a defined Adverse Change has occurred, then all restrictions on the award will lapse, the units will become vested and the vested units will be delivered to the Named Executive Officer as soon as practicable, as follows:

				Equity Incentive PlanAwards:
	Market Value of Unvested Units			Market Value of Unvested Units
Name	Upon a Change in Control			Upon a Change in Control
Matthew P. Clifton		n/a		$	823,475	(1)
Stephen J. McDonnell	$	70,639	(2)		n/a
P. Dean Ridenour	$	285,614	(2)		n/a
James G. Townsend	$	130,048	(2)		n/a

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(1)	Based upon (i) a payment of 100% of the units described at the Outstanding Equity Awards at Fiscal Year End Table in footnote (1)A and (ii) a payment of 150% of the units described in footnote (1)B above, as provided for under the terms of the long-term incentive equity agreements governing the awards, at the closing price of $40.25 on December 29, 2006.
(2)	Based upon a payment of 100% of the units as provided for under the terms of the long-term incentive equity agreements governing the awards of the units, at the closing price of $40.25 on December 29, 2006.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth as of February 21, 2007 the beneficial ownership of units of HEP held by beneficial owners of 5% or more of the units, by directors of HLS, the general partner of our general partner, by each executive officer and by all directors and executive officers of HLS as a group. HEP Logistics Holdings, L.P. is an indirect wholly-owned subsidiary of Holly Corporation. Unless otherwise indicated, the address for each unitholder shall be c/o Holly Energy Partners, L.P., 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915.

							Percentage
			Percentage				of		Percentage
	Common		of Common		Subordinated		Subordinated		of Total
	Units		Units		Units		Units		Units
	Beneficially		Beneficially		Beneficially		Beneficially		Beneficially
Name of Beneficial Owner	Owned		Owned		Owned		Owned		Owned
Holly Corporation (1)		70,000		0.9		7,000,000		88.2		45.0
HEP Logistics Holdings, L.P.(1)		70,000		0.9		7,000,000		88.2		45.0
Fiduciary Asset Management, LLC(2)		951,510		11.6		0		0.0		5.9
Alon USA		0		0.0		937,500		11.8		5.8
Kayne Anderson Capital Advisors, L.P.(3)		786,400		9.6		0		0		4.9
Tortoise Capital Advisors LLC(4)		572,689		7.0		0		0		3.6
Matthew P. Clifton		45,240		*		0		0		*
David G. Blair		3,100		*		0		0		*
W. John Glancy		1,000		*		0		0		*
Stephen J. McDonnell		14,645		*		0		0		*
P. Dean Ridenour(5)		15,632		*		0		0		*
James G. Townsend		4,909		*		0		0		*
Lamar Norsworthy		0		0.0		0		0		0.0
Charles M. Darling, IV(5)		14,709		*		0		0		*
Jerry W. Pinkerton(5)		4,509		*		0		0		*
William P. Stengel(5)		3,509		*		0		0		*
All directors and executive officers as group (9 persons) (5)		98,815		1.2		0		0		*

* Less than 1%

(1)	Holly Corporation is the ultimate parent company of HEP Logistics Holdings, L.P., and may, therefore, be deemed to beneficially own the units held by HEP Logistics Holdings, L.P. Holly Corporation files information with or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Exchange Act. The percentage of total units beneficially owned includes a 2% general partner interest held by HEP Logistics Holdings, L.P.
(2)	Fiduciary Asset Management, LLC has filed with the SEC a Schedule 13G/A, dated August 16, 2005. Based on this Schedule 13G/A, Fiduciary Asset Management, LLC has sole voting power and sole dispositive power with respect to 951,510 units, and shared voting and dispositive power with respect to zero units. The address of Fiduciary Asset Management, LLC is 8112 Maryland Avenue, Suite 400 St. Louis, MO 63105.
(3)	Kayne Anderson Capital Advisors, L.P. has filed with the SEC a Schedule 13G, dated January 30, 2007. Based on this Schedule 13G, Kayne Anderson Capital Advisors, L.P. has sole voting power and sole dispositive power with respect to zero units, and shared voting power and shared dispositive power with respect to 786,400 units. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Second Floor, Los Angeles, CA 90067.
(4)	Tortoise Capital Advisors LLC has filed with the SEC a Schedule 13G/A, dated February 13, 2007. Based on this Schedule 13G/A, Tortoise Capital Advisors LLC has sole voting power and sole dispositive power with respect to zero units, shared voting power with respect to 534,637 units and shared dispositive power

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	with respect to 572,689 units. The address of Tortoise Capital Advisors LLC is 10801 Mastin Blvd., Suite 222, Overland Park, Kansas 66210.
(5)	The number of units beneficially owned includes restricted common units granted as follows: 3,509 units each to Mr. Darling, Mr. Pinkerton and Mr. Stengel, 7,802 units to Mr. Clifton, 7,096 units to Mr. Ridenour, 3,231 units to Mr. Townsend, and 1,755 units to Mr. McDonnell, and 8,438 performance units to Mr. Clifton, a total of 38,849 units.

Equity Compensation Plan Table

The following table summarizes information about our equity compensation plans as of December 31, 2006:

	Number of Securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected)
Equity compensation plans approved by security holders		—		—		—
Equity compensation plans not approved by security holders		—		—		291,419
Total		—				291,419

For more information about our Long-Term Incentive Plan, which did not require approval by our limited partners, refer to Item 11, “Executive and Director Compensation — Long-Term Incentive Plans”.

Item 13. Certain Relationships, Related Transactions and Director Independence

Our general partner and its affiliates own 7,000,000 of our subordinated units and 70,000 of our common units, which combined represent a 43% limited partner interest in us. In addition, the general partner owns a 2% general partner interest in us. Transactions with the general partner are discussed below.

On February 28, 2005, we completed the transactions with Alon described on page 8 of this report, by which we acquired certain pipelines and terminals from Alon for $120.0 million in cash and 937,500 of our Class B subordinated units and entered into our pipelines and terminals agreement with Alon. Following this transaction, Alon owns all of our Class B subordinated units, which comprise approximately 5.7% of our total outstanding equity ownership. During the year ended December 31, 2006, we received revenues of $18.0 million from Alon pursuant to the pipelines and terminals agreement and $6.9 million from Alon pursuant to capacity lease arrangements on our Orla to El Paso pipeline.

DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and liquidation of HEP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

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Operational stage

Distributions of available cash to our general partner and its affiliates	We generally make cash distributions 98% to the unitholders, including our general partner and its affiliates as the holders of an aggregate of 7,000,000 of the subordinated units, 70,000 common units and 2% to the general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner is entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.
Payments to our general partner and its affiliates	We pay Holly or its affiliates an administrative fee, currently $2.0 million per year, for the provision of various general and administrative services for our benefit. The administrative fee may increase following the second and third anniversaries by the greater of 5% or the percentage increase in the consumer price index and may also 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. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of HLS who provide services to us. Please read “Omnibus Agreement” below. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

OMNIBUS AGREEMENT

On July 13, 2004, we entered into the Omnibus Agreement with Holly and our general partner that addressed the following matters:

• our obligation to pay Holly an annual administrative fee, currently in the amount of $2.0 million, for the provision by Holly of certain general and administrative services;

• Holly’s and its affiliates’ agreement not to compete with us under certain circumstances;

• an indemnity by Holly for certain potential environmental liabilities;

• our obligation to indemnify Holly for environmental liabilities related to our assets existing on the date of our initial public offering to the extent Holly is not required to indemnify us;

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• our three-year option to purchase the Intermediate Pipelines owned by Holly; and

• Holly’s right of first refusal to purchase our assets that serve Holly’s refineries.

Payment of general and administrative services fee

Under the Omnibus Agreement we pay Holly an annual administrative fee, currently in the amount of $2.0 million, for the provision of various general and administrative services for our benefit. The contract provides that this amount may be increased on the third anniversary following our initial public offering by the greater of 5% or the percentage increase in the consumer price index for the applicable year. Our general partner, with the approval and consent of its conflicts committee, also has the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses. Following the initial three-year period under this agreement, our general partner will determine the general and administrative expenses that will be allocated to us.

The $2.0 million fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. The fee does not include salaries of pipeline and terminal personnel or other employees of HLS 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 general and administrative expenses they incur on our behalf.

Noncompetition

Holly and its affiliates have agreed, for so long as Holly controls our general partner, not to engage in, whether by acquisition or otherwise, the business of operating crude oil pipelines or terminals, refined products pipelines or terminals, Intermediate Pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. This restriction will not apply to:

• any business operated by Holly or any of its affiliates at the time of the closing of our initial public offering;

• any business conducted by Holly with the approval of our conflicts committee;

• any crude oil pipeline or gathering system acquired or constructed by Holly or any of its affiliates after the closing of our initial public offering that is physically interconnected to Holly’s refining facilities;

• any business or asset that Holly or any of its affiliates 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 affiliates 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.

The limitations on the ability of Holly and its affiliates to compete with us will terminate if Holly ceases to control our general partner.

Indemnification

Under the Omnibus Agreement, Holly indemnifies us for ten years from July 13, 2004 against certain potential environmental liabilities associated with the operation of the assets and occurring before the closing date of our initial public offering. Holly’s maximum liability for this indemnification obligation will not exceed $15.0 million and Holly will not have any obligation under this indemnification until our losses exceed $200,000. Holly has agreed to provide $2.5 million of additional indemnification above that previously provided in the Omnibus Agreement for environmental noncompliance and remediation liabilities occurring or existing before the closing date of the Intermediate Pipelines transaction, bringing

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the total indemnification provided to us from Holly to $17.5 million. Of this total, indemnification above $15.0 million relates solely to the Intermediate Pipelines.

We indemnified Holly and its affiliates against environmental liabilities related to our assets existing on the date of our initial public offering to the extent Holly has not indemnified us.

Right of first refusal to purchase our assets

The Omnibus Agreement also contains the terms under which Holly has a right of first refusal to purchase our assets that serve its refineries. Before we enter into any contract to sell pipeline and terminal assets serving Holly’s refineries, we must give written notice of the terms of such proposed sale to Holly. The notice must set forth the name of the third party purchaser, the assets to be sold, the purchase price, all details of the payment terms and all other terms and conditions of the offer. To the extent the third party offer consists of consideration other than cash (or in addition to cash), the purchase price shall be deemed equal to the amount of any such cash plus the fair market value of such non-cash consideration, determined as set forth in the Omnibus Agreement. Holly will then have the sole and exclusive option for a period of thirty days following receipt of the notice, to purchase the subject assets on the terms specified in the notice.

PIPELINES AND TERMINALS AGREEMENTS

At the time of our initial public offering, we entered into a pipelines and terminals agreement with Holly, and in July 2005, we entered into an Intermediate Pipelines agreement, both as described under “Business — Agreements with Holly” under Item 1 of this Form 10-K Annual Report.

Holly’s obligations under this agreement will not terminate if Holly and its affiliates no longer own the general partner. These agreements may be assigned by Holly only with the consent of our conflicts committee.

SUMMARY OF TRANSACTIONS WITH HOLLY

• Pipeline and terminal revenues received from Holly were $52.9 million, $44.2 million and $45.3 million for the years ended December 31, 2006, 2005 and 2004, respectively. These amounts include the revenues received under the pipelines and terminals agreements as well as revenues received by the predecessor prior to formation in July 2004.

• Holly charged general and administrative services under the Omnibus Agreement of $2.0 million for the years ended December 31, 2006 and 2005 and $0.9 million for the year ended December 31, 2004.

• We reimbursed Holly for costs of employees supporting our operations of $7.7 million, $6.5 million and $2.2 million for the years ended December 31, 2006, 2005 and 2004.

• In the years ended December 31, 2006 and 2005, Holly reimbursed $0.2 million to us for certain costs paid on their behalf. In the year ended December 31, 2004, we reimbursed Holly $3.9 million for certain formation, debt issuance and other costs paid on our behalf.

• In the years ended December 31, 2006, 2005 and 2004, we distributed $20.3 million, $16.5 million and $3.2 million, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest.

• We acquired the Intermediate Pipelines from Holly in July 2005, which resulted in payment to Holly of a purchase price of $71.9 million in excess of the basis of the assets received. See Note 3 to our consolidated financial statements for further information on the Intermediate Pipelines transaction.

• In the year ended December 31, 2004, we distributed $125.6 million to Holly concurrent with our initial public offering and we repaid $30.1 million to Holly for short-term borrowings that originated in 2003.

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Item 14. Principal Accountant Fees and Services

The audit committee of the board of directors of HLS selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the Partnership for the 2006 calendar year.

Fees paid to Ernst & Young LLP for 2006 and 2005 are as follows:

	2006		2005
Audit Fees(1)	$	387,900	$	457,820
Audit Related Fees		—		—
Tax Fees(2)		—		—
All Other Fees		—		—
Total	$	387,900	$	457,820

(1)	Represents fees for professional services provided in connection with the audit of our annual financial statements and internal controls over financial reporting, review of our quarterly financial statements, and audits performed as part of our securities filings.
(2)	Tax services are among the administrative services that Holly provides to HEP under the Omnibus Agreement. Therefore, Holly paid $401,000 and $373,000 to Ernst & Young LLP for tax services provided to HEP in the years ended December 31, 2006 and 2005, respectively.

The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website atwww.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 services reported in the audit, audit-related, tax and all other fees categories above were approved by the audit committee in advance.

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Part IV

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

(a) Documents filed as part of this report

(1) Index to Consolidated Financial Statements

	Page in
	Form 10-K
Report of Independent Registered Public Accounting Firm		55
Consolidated Balance Sheets at December 31, 2006 and 2005		56
Consolidated Statements of Income for the years ended December 31, 2006 and 2005, the period from July 13, 2004 through December 31, 2004, and the period from January 1, 2004 through July 12, 2004		57
Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005, the period from July 13, 2004 through December 31, 2004, and the period from January 1, 2004 through July 12, 2004		58
Consolidated Statements of Partners’ Equity for the years ended December 31, 2006 and 2005, the period from July 13, 2004 through December 31, 2004, and the period from January 1, 2004 through July 12, 2004		59
Notes to Consolidated Financial Statements		60

(2) Index to Consolidated Financial Statement Schedules

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

(3) Exhibits

2.1	Contribution Agreement, dated January 25, 2005, by and among Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., T&R Assets, Inc., Fin-Tex Pipe Line Company, Alon USA Refining, Inc., Alon Pipeline Assets, LLC, Alon Pipeline Logistics, LLC, Alon USA, Inc., and Alon USA, L.P. (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K Current Report dated January 25, 2005).
2.2	Purchase and Sale Agreement, dated July 6, 2005 by and among Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.P., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P. and HEP Pipeline, L.L.C. (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K Current Report dated July 6, 2005).
3.1	First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

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3.2	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated February 28, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
3.3	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., as amended, dated July 6, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
3.4	First Amended and Restated Agreement of Limited Partnership of HEP Operating Company, L.P. (incorporated by reference to Exhibit 3.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.5	Certificate of Amendment to the Certificate of Limited Partnership of HEP Operating Company, L.P., dated July 30, 2004, changing the name from HEP Operating Company, L.P. to Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 3.3 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.6	First Amended and Restated Agreement of Limited Partnership of HEP Logistics Holdings, L.P. (incorporated by reference to Exhibit 3.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.7	First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 3.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.8	First Amended and Restated Limited Liability Company Agreement of HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 3.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
4.1	Indenture, dated February 28, 2005, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
4.2	Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture filed as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
4.3	Form of Notation of Guarantee (included as Exhibit E to the Indenture filed as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
4.4	Registration Rights Agreement, dated February 28, 2005, among the Issuers and the Initial Purchasers (incorporated by reference to Exhibit 4.4 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
4.5	First Supplemental Indenture, dated March 10, 2005, among HEP Fin-Tex/Trust-River, L.P., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2005, File No. 1-32225).
4.6	Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National

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	Association (incorporated by reference to Exhibit 4.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2005, File No. 1-32225).
4.7	Registration Rights Agreement, dated June 28, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp. and the Initial Purchasers identified therein (incorporated by reference to Exhibit 4.3 of Registrant’s Form 8-K Current Report dated June 28, 2005, File No. 1-32225).
4.8	Registration Rights Agreement, dated July 8, 2005, among Holly Energy Partners, L.P., Fiduciary/Claymore MLP Opportunity Fund, Perry Partners, L.P., Structured Finance Americas, LLC, Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total Return Fund, Inc. (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
10.1	Credit Agreement, dated as of July 7, 2004, among HEP Operating Company, L.P., as borrower, the financial institutions party to this agreement, as banks, Union Bank of California, N.A., as administrative agent and sole lead arranger, Bank of America, National Association, as syndication agent, and Guaranty Bank, as documentation agent (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.2	Consent and Agreement, entered into as of July 13, 2004 (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.3	Consent, Waiver and Amendment No. 2, dated February 28, 2005, among OLP, the existing guarantors identified therein, Union Bank of California, N.A., as administrative agent, and certain other lending institutions identified therein (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated February 28, 2005).
10.4	Waiver and Amendment No. 3, dated June 17, 2005, among Holly Energy Partners, L.P., Union Bank of California, N.A., as administrative agent, and certain other lending institutions identified therein (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2005, File No. 1-32225).
10.5	Consent and Amendment No. 4, dated July 8, 2005, among Holly Energy Partners, L.P., Union Bank of California, N.A., as administrative agent, and certain other lending institutions identified therein (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
10.6	Pledge Agreement, dated as of July 13, 2004 (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.7	Guaranty Agreement, dated as of July 13, 2004 (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.8	Security Agreement, dated as of July 13, 2004 (incorporated by reference to Exhibit 10.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.9	Form of Mortgage, Deed of Trust, Security Agreement, Assignment of Rents and Leases, Fixture Filing and Financing Statement, dated July 13, 2004 (incorporated by reference to Exhibit 10.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

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10.10	Form of Mortgage and Deed of Trust (Oklahoma) (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
10.11	Form of Mortgage and Deed of Trust (Texas) (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
10.12	Mortgage and Deed of Trust, dated July 8, 2005, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
10.13	Omnibus Agreement, effective as of July 13, 2004, among Holly Corporation, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and HEP Operating Company, L.P. (incorporated by reference to Exhibit 10.7 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.14	Pipelines and Terminals Agreement, dated July 13, 2004, by and among Holly Corporation, Navajo Refining Company, L.P., Holly Refining and Marketing Company, Holly Energy Partners, L.P., HEP Operating Company, L.P., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C., and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.8 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.15	Pipelines and Terminals Agreement, dated February 28, 2005, among the Partnership and Alon USA, LP2005 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
10.16	Pipelines Agreement, dated July 8, 2005, among Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., Holly Corporation, HEP Pipeline, L.L.C., Navajo Refining Company, L.P., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
10.17+	Holly Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.18+	Holly Logistic Services, L.L.C. Annual Incentive Plan (incorporated by reference to Exhibit 10.10 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.19+	Form of Director Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K dated November 15, 2004, File No. 1-32225).
10.20+	Form of Employee Restricted Unit Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K dated November 15, 2004, File No. 1-32225).
10.21+	Form of Restricted Unit Agreement (with Performance Vesting) (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated August 4, 2005, File No. 1-32225).

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10.22+	Form of Restricted Unit Agreement (without Performance Vesting) (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated August 4, 2005, File No. 1-32225).
10.23+	Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated January 12, 2007, File No. 1-32225).
10.24+	First Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2005, File No. 1-32225).
10.25+	Form of Amendment to Performance Unit Agreement Under the Holly Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Current Report dated February 10, 2006, File No. 1-32225).
12.1*	Statement of Computation of Ratio of Earnings to Fixed Charges.
21.1*	Subsidiaries of Registrant.
23.1*	Consent of Independent Registered Public Accounting Firm.
31.1*	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith.
+	Constitutes management contracts or compensatory plans or arrangements.

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	HOLLY ENERGY PARTNERS, L.P.
	(Registrant)
	By: HEP LOGISTICS HOLDINGS, L.P.
	its General Partner
	By: HOLLY LOGISTIC SERVICES, L.L.C.
	its General Partner
Date: February 23, 2007	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chairman of the Board of Directors and
	Chief Executive Officer
	/s/ P. Dean Ridenour
	P. Dean Ridenour
	Vice President and Chief Accounting
	Officer and Director
	(Principal Accounting Officer)
	/s/ Stephen J. McDonnell
	Stephen J. McDonnell
	Vice President and Chief Financial Officer
	(Principal Financial Officer)
	Lamar Norsworthy
	Director
	/s/ Charles M. Darling, IV
	Charles M. Darling, IV
	Director
	/s/ Jerry W. Pinkerton
	Jerry W. Pinkerton
	Director
	/s/ William P. Stengel
	William P. Stengel Director

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