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

HOLLY ENERGY PARTNERS, L.P.

Securities registered pursuant to Section 12(b) of the Act:
Common Limited Partner Units

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No þ

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

Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in part III of 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 filer o		Accelerated filer þ		Non-accelerated filer   o (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $412 million on June 30, 2007, 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 13, 2008 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			13
1B.		Unresolved staff comments			25
2.		Properties			25
3.		Legal proceedings			32
4.		Submission of matters to a vote of security holders			32
		PART II
5.		Market for the Registrant’s common units, related unitholder matters and issuer purchases of common units			33
6.		Selected financial data			35
7.		Management’s discussion and analysis of financial condition and results of operations			38
7A.		Quantitative and qualitative disclosures about market risk			55
8.		Financial statements and supplementary data			56
9.		Changes in and disagreements with accountants on accounting and financial disclosure			85
9A.		Controls and procedures			85
9B.		Other information			85
		PART III
10.		Directors, executive officers and corporate governance			86
11.		Executive compensation			91
12.		Security ownership of certain beneficial owners and management and related unitholder matters			113
13.		Certain relationships, related transactions and director independence			114
14.		Principal accountant fees and services			118
		PART IV
15.		Exhibits and financial statement schedules			119
Signatures					124
Statement of Compuation 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

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 additional operations in the future;
	•		Our ability to complete previously announced pending or contemplated acquisitions;
	•		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.

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
Big Spring Refinery			5
BP			15
bpd			6
Credit Agreement			50
Distributable cash flow			42
DOT			10
EBITDA			36
FERC			11
GAAP			36
HEP			5
HLS			5
Holly			5
Holly IPA			5
Holly PTA			5
Intermediate Pipelines			5
Kinder Morgan			6
LIBOR			51
LPG			6
Maintenance capital expenditures			36
mbbls			26
mbpd			43
Mid-America			26
Navajo Refinery			5
NPL			5
NuStar			30
Plains			9
PPI			6
Purchase Agreement			8
Rio Grande			5
SEC			5
Senior Notes			7
SFAS			54
Sinclair			31
South System			6
ULSD			43
UNEV Pipeline			9
Valero			30

Terms used in the financial statements and footnotes are as defined therein.

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 acquired 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”) upon the closing of its initial public offering in July 2004.

On February 28, 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 located primarily in Texas. On July 8, 2005, we acquired 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, Texas refinery (“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;
	•		approximately 510 miles of refined product pipelines that transport refined products from Alon’s Big Spring Refinery in Texas to its customers in Texas and Oklahoma;
	•		two parallel 65-mile pipelines that transport intermediate feedstocks and crude oil from Holly’s Lovington, New Mexico refinery facilities to Holly’s Artesia, New Mexico refinery facilities; 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:

	•		four refined product terminals (one of which is 50% owned), located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 900,000 barrels, that are integrated with our refined product pipeline system that serves Holly’s Navajo Refinery;
	•		three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000 barrels, that serve third-party common carrier pipelines;
	•		one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;
	•		two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with our refined product pipelines that serve Alon’s Big Spring Refinery; 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.

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, 2007 PPI adjustment, the volume commitments by Holly under the Holly PTA will produce a minimum of $39.6 million of revenue for the twelve months ending June 30, 2008. 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 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.

In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso, Texas (the “South System”). The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan L.P. (“Kinder Morgan”) pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete this project by January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008, on Holly shipments on our refined product pipelines.

Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the

right after we have made efforts to mitigate their effects to negotiate a monthly surcharge on Holly for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly’s pro rata portion of the cost of complying with these laws or regulations. In such instances, we will negotiate in good faith with Holly 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 certain provisions of an omnibus agreement that we entered with Holly in July 2004 and expires in 2019 (the “Omnibus Agreement”), we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Initially, this fee was $2.0 million for each of the three years following the closing of our initial public offering. Effective July 1, 2007, the annual fee increased to $2.1 million in accordance with provisions under the agreement. This 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 Holly and its affiliates for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees. Under the Omnibus Agreement, Holly 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, 2007 PPI rate adjustment, Alon’s total minimum commitment for the twelve months ending February 29, 2008 is $20.9 million. 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. Fair values of the assets acquired were estimated using the cost, market and income approach methodologies. Under the cost approach, management determined the fair value of acquired tangible pipeline and terminal assets based on the estimated replacement cost of assets using current costs, adjusted for the effects of physical depreciation and physical deterioration. The fair value of acquired rights of way was determined using the market approach based on publicly available market data. The value of the transportation agreement was determined using the income approach, under which management estimated the net present value of the after-tax earnings attributable to the Alon PTA over a 30-year life (the 15-year initial term plus the expected 15 years of extension periods), plus the value of the tax benefit of amortization.

Holly Intermediate Pipelines Transaction

On July 8, 2005, we acquired pursuant to a definitive purchase agreement (the “Purchase Agreement”) Holly’s Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. The total consideration was $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 an agreement with Holly to transport volumes of intermediate products on the Intermediate Pipelines that expires in 2020. Under the Holly IPA, Holly agreed to transport volumes of product 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, 2007 PPI adjustment, the volume commitments by Holly under the Holly IPA will result in minimum funds to us of $12.8 million for the twelve months ending June 30, 2008. 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.

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 with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated to a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years.

In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete this project by January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008, on Holly shipments on our refined product pipelines.

In November 2007, we announced an agreement in principle for the acquisition of certain pipeline and tankage assets from Holly for approximately $180.0 million. The consideration is expected to consist of $171.0 million in cash and our common units valued at approximately $9.0 million. The assets include 136 miles of crude oil trunk lines that deliver crude to Holly’s Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000 barrels of storage capacity located within the Navajo and Woods Cross refinery complexes, a jet fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support Holly’s Woods Cross Refinery. In connection with the closing of this proposed transaction, we intend to enter into a 15-year pipelines and tankage agreement with Holly that will contain a minimum annual revenue commitment to us from Holly. Both the HLS and Holly boards of directors have approved this proposed transaction, which we expect to close in the first quarter of 2008.

In November 2007, we executed a definitive agreement with Plains All American Pipeline, L.P. (“Plains”) to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area (the “SLC Pipeline”). Under the agreement, the SLC Pipeline will be owned by a joint venture company which will be owned 75% by Plains and 25% by us. Subject to the actual cost of the SLC Pipeline, we will purchase our 25% interest in the joint venture for an amount between $22.0 and $25.5 million in the second quarter of 2008, when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including Holly’s Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah, which is currently flowing on Plains’ Rocky Mountain Pipeline.

On January 31, 2008, we entered into an option agreement with Holly, granting us an option to purchase all of Holly’s equity interests in a joint venture pipeline currently under construction. The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the “UNEV Pipeline”). Holly currently owns 75% of the equity interests in the UNEV Pipeline. Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million. Holly’s share of this cost is $225.0 million. Construction of this project is currently expected to be completed and operational in mid 2009.

We are also studying several other projects, which are in various stages of analysis.

We expect that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for capital development projects such as the UNEV Pipeline, SLC Pipeline and South System expansion projects described above will be funded with existing cash balances, cash generated by operations, the sale of additional limited partner units and advances under our $100 million senior secured revolving credit agreement maturing August 2011 (the “Credit Agreement”).

Additionally, we plan to upsize our Credit Agreement to fund the cash portion of the consideration for our announced purchase of certain pipeline and tankage assets from Holly described above.

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, 2007 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, 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.

However, we do face competition from other pipelines that may be able to supply the end-user markets of Holly or Alon with refined products on a more competitive basis. Additionally, If Holly’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.

The petroleum refining business is highly competitive. Among Holly’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. Holly competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.

In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.

Historically, the significant majority of the throughput at our terminal facilities has come from Holly, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso, and the Abilene and Wichita Falls terminals that serve Alon’s Big Springs Refinery. Under the terms of the Holly PTA, we continue to receive a significant portion of the throughput at our terminal facilities from Holly.

Our ten refined product terminals compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location, price, versatility and services provided. Our competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms.

RATE REGULATION

Some of our existing pipelines are subject to rate regulation by the 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. However, a state regulatory commission could investigate our rates if such a challenge were filed.

ENVIRONMENTAL REGULATION AND REMEDIATION

Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. Although these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

We inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.

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 the remediation of 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 $2.0 million over the next four 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, 2007, 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 at a point along our refined product pipeline from Artesia, New Mexico to Orla, Texas. As of At December 31, 2007, we estimate the remaining cost on this project to be $0.3 million, half of which will be incurred in 2008. 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 remediation projects mentioned above, including assessment, monitoring, and remediation programs.

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 106 people who provide direct support to our operations, of which 6 are covered by collective bargaining agreements that expire in March 2009. Holly Logistic Services, L.L.C. considers its employee relations to be good. Neither we nor our general partner have employees. We reimburse Holly for direct expenses that Holly or its affiliates incurs on our behalf for the employees of HLS.

Item 1A. Risk Factors

Investing in us involves a degree of risk, including the risks described below. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition, results of operations or treatment of unitholders could be materially and adversely affected.

We depend upon Holly and particularly its Navajo Refinery for a majority of our revenues; 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, 2007, Holly accounted for 58% of the revenues of our petroleum products pipelines and 67% 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, 2007, production from the Navajo Refinery accounted for 55% 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;
	•		increasingly stringent environmental laws and regulations, such as the Environmental Protection Agency’s gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road usage as well as various state and federal emission requirements that may affect the refinery itself;
	•		an inability to obtain crude oil for the refinery at competitive prices; or
	•		a general reduction in demand for refined products in the area due to:

	-		a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel;
	-		higher gasoline prices due to higher crude oil prices, higher taxes or stricter environmental laws or regulations; or
	-		a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation either mandating or encouraging higher fuel economy or the use of alternative fuel or otherwise.

The magnitude of the effect on us of any shutdown would depend on the length of the shutdown and the extent of the refinery operations affected by the shutdown. We have no control over the factors that may lead to a shutdown or the measures Holly may take in response to a shutdown. Holly makes all decisions at the Navajo Refinery concerning levels of production, regulatory compliance, refinery turnarounds (planned shutdowns of individual process units within the refinery to perform major maintenance activities), labor relations, environmental remediation and capital expenditures; is responsible for all related costs; and is under no contractual obligation to us to maintain operations at the Navajo Refinery.

Furthermore, Holly’s obligations under the Holly PTA and Holly IPA would be temporarily suspended during the occurrence of a force majeure that renders performance impossible with respect to an asset for at least 30 days. If such an event were to continue for a year, we or Holly could terminate the agreements. The occurrence of any of these events could reduce our revenues and cash flows.

We depend on Alon and particularly its Big Spring Refinery for a substantial portion of our revenues; if those revenues were significantly reduced, there would be a material adverse effect on our results of operations.

For the year ended December 31, 2007, Alon accounted for 27% 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 a force majeure event occurs beyond the control of either of us, we or Alon could terminate the Alon pipelines and terminals agreement after the expiration of certain time periods. The occurrence of any of these events could reduce our revenues and cash flows.

We are exposed to the credit risks of our key customers.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. As stated above, we receive substantial revenues from both Holly and Alon under their respective pipelines and terminals agreements. In addition, a subsidiary of BP Plc (“BP”) is 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, 2007.

If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks.

Competition from other pipelines that may be able to supply our shippers’ customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.

We and our shippers could face increased competition if other pipelines are able to competitively supply our shippers’ end-user markets with refined products. The Longhorn Pipeline is a 72,000 bpd common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. Deliveries of refined products shipped on the Longhorn Pipeline increased significantly during 2007, and we believe is currently operating at or near full capacity. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has also announced a planned expansion of its pipeline from 72,000 bpd to 125,000 bpd. Also in 2007, Kinder Morgan completed an expansion of its El Paso, Texas to Tucson and Phoenix, Arizona pipeline, increasing its capacity to 200,000 bpd. Increased supplies of refined product delivered by the Longhorn Pipeline and Kinder Morgan’s El Paso to Phoenix pipeline could result in additional downward pressure on wholesale refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from Holly and/or Alon. Such eventuality could reduce our opportunity to earn revenues from Holly and Alon in excess of their minimum volume commitment obligations.

An additional factor that could affect some of Holly’s and Alon’s markets is excess pipeline capacity from the West Coast into our shippers’ Arizona markets on the pipeline from the West Coast to Phoenix. Additional increases in shipments of refined products from the West Coast into our shippers’ Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by Holly and Alon to these markets.

A material decrease in the supply, or a material increase in the price, of crude oil available to Holly’s and Alon’s refineries, 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.

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 four to twelve years. BP’s agreement to ship on the Rio Grande Pipeline expires in April 2008. Our pipelines and terminals agreements with Holly and Alon expire in 2019 and 2020, respectively.

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 could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of

coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.

Holly, Alon and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals. For example, the common carrier pipelines used by Holly to serve the Arizona and Albuquerque markets are currently operated at or near capacity and are subject to proration. As a result, the volumes of refined product that Holly and other shippers have been able to deliver to these markets have been limited. The flow of additional products into El Paso for shipment to Arizona could further exacerbate such constraints on deliveries to Arizona. Any reduction in volumes transported in our pipelines or through our terminals could adversely affect our revenues and cash flows.

If our assumptions concerning population growth are inaccurate or if Holly’s growth strategy is not successful, our ability to grow may be adversely affected.

Our growth strategy is dependent upon:

	•		the accuracy of our assumption that many of the markets that we currently serve or have plans to serve in the Southwestern and Rocky Mountain regions of the United States will experience population growth that is higher than the national average; and
	•		the willingness and ability of Holly to capture a share of this additional demand in its existing markets and to identify and penetrate new markets in the Southwestern and Rocky Mountain regions of the United States.

If our assumptions about growth in market demand prove incorrect, Holly may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy. Furthermore, Holly is under no obligation to pursue a growth strategy. If Holly chooses not to gain, or is unable to gain additional customers in new or existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth strategy would be adversely affected. Moreover, Holly may not make acquisitions that would provide acquisition opportunities to us; or, if those opportunities arise, they may not be 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 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 CFR 342-3, our interstate pipeline tariff rates are deemed just and reasonable. If a party with an economic interest were to file either a protest or a complaint against our tariff rates, 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 or domestic vandalism, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

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

Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt.

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

As of December 31, 2007, 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 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 agreements with Alon and with Holly with respect to the Intermediate Pipelines restrict us from selling the pipelines and terminals acquired from Alon or Holly, as applicable, and from prepaying more than $30.0 million of the Senior Notes until 2015, 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.

Risks to Common Unitholders

Holly and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.

Currently, Holly indirectly owns the 2% general partner interest and a 43% limited partner interest in us and owns and controls our general partner, HEP Logistics Holdings, L.P. Conflicts of interest may arise between Holly and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following situations:

	•		Holly, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm’s-length, third-party transactions;
	•		neither our partnership agreement nor any other agreement requires Holly to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. Holly’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Holly;
	•		our general partner is allowed to take into account the interests of parties other than us, such as Holly, in resolving conflicts of interest;
	•		our general partner determines which costs incurred by Holly and its affiliates are reimbursable by us;
	•		our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
	•		our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash available to us; and
	•		our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with Holly.

Cost reimbursements, which will be determined by our general partner, and fees due our general partner and its affiliates for services provided, are substantial.

Under our partnership agreement, we are currently obligated to pay Holly an administrative fee of $2.1 million per year for the provision by Holly or its affiliates of various general and administrative services for our benefit. The administrative fee may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from Holly or its affiliates. Our general partner will determine the amount of general and administrative expenses that will be properly allocated to us in accordance with the terms of our partnership agreement. In addition, our general partner and its affiliates are entitled to reimbursement for all other expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees of Holly Logistic Services, L.L.C. who provide services to us. Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we are charged fees as determined by our general partner.

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner’s general partner and have no right to elect our general partner or the board of directors of our general partner’s general partner on an annual or other continuing basis. The board of directors of our general partner’s general partner is chosen by the members of our general partner’s general partner. Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Unitholders will be unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to prevent its removal. Also, if the general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner’s general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their respective partnership interests in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner of our general partner with their own choices and to control the decisions taken by the board of directors and officers.

We may issue additional common units without unitholder approval, which would dilute an existing unitholder’s ownership interests.

During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 3,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:

	•		the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on an estimated pro forma basis;
	•		issuances of common units to repay indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the repayment of the indebtedness;
	•		the conversion of subordinated units into common units;
	•		the conversion of units of equal rank with the common units into common units under some circumstances;
	•		in the event of a combination or subdivision of common units;

	•		issuances of common units under our employee benefit plans; or
	•		the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal or removal of our general partner.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

	•		our unitholders’ proportionate ownership interest in us will decrease;
	•		the amount of cash available for distribution on each unit may decrease;
	•		because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	•		the relative voting strength of each previously outstanding unit may be diminished; and
	•		the market price of the common units may decline.

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available to make the required payments to our debt holders or to pay the minimum quarterly distribution on our common units every quarter.

Holly and its affiliates may engage in limited competition with us.

Holly and its affiliates may engage in limited competition with us. Pursuant to the omnibus agreement among us, Holly and our general partner, Holly and its affiliates agreed not to engage in the business of operating intermediate or refined product pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. The omnibus agreement, however, does not apply to:

	•		any business operated by Holly or any of its subsidiaries at the closing of our initial public offering;
	•		any crude oil pipeline or gathering system acquired or constructed by Holly or any of its subsidiaries that is physically interconnected to Holly’s refining facilities;
	•		any business or asset that Holly or any of it subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5.0 million; and
	•		any business or asset that Holly or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5.0 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so with the concurrence of our conflicts committee.

In the event that Holly or its affiliates no longer control our partnership or there is a change of control of Holly, the non-competition provisions of the omnibus agreement will terminate.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.

In some instances, our general partner may cause us to borrow funds from affiliates of Holly or from third parties in order to permit the payment of cash distributions.

These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions, or to hasten the expiration of the subordination period.

Our general partner has a limited call right that may require a holder of units to sell its common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, a holder of common units may be required to sell its units at an undesirable time or price and may not receive any return on its investment. A common unitholder may also incur a tax liability upon a sale of its units.

A unitholder may not have limited liability if a court finds that unitholder actions constitute control of our business.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the current maximum corporate tax rate of 35%. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take on tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

Unitholders may be required to pay taxes on their share of taxable income even if they do not receive any cash distributions from us.

Unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

Tax gain or loss on the disposition of our common units could be different than expected.

If a unitholder sells common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income it was allocated for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income.

Tax-exempt entities, regulated investment companies or foreign persons may have adverse tax consequences from owning common units.

Investment in common units by tax-exempt entities, regulated investment companies or mutual funds and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Recent legislation treats net income derived from the ownership of certain publicly traded partnerships (including us) as qualifying income to a regulated investment company. Distributions to foreign persons will be reduced by withholding taxes at the highest effective U.S. federal income tax rate for individuals, and foreign persons will be required to file federal income tax returns and pay tax on their share of our taxable income.

We treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not precisely conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholder tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in New Mexico, Arizona, Texas, Washington, Utah, Oklahoma and Idaho. Of those states, only Texas and Washington do not currently impose a state income tax. We may own property or conduct business in other states or foreign countries in the future. It is the unitholder’s responsibility to file all federal, state and local tax returns.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

Item 1B. Unresolved Staff Comments

We do not have any unresolved SEC staff comments.

Item 2. Properties

PIPELINES

Our refined product pipelines transport light refined products from Holly’s Navajo Refinery in New Mexico and Alon’s Big Spring Refinery in Texas to their customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah, Oklahoma and northern Mexico. The refined products transported in these pipelines include conventional gasolines, federal, state and local specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that include high- and low-sulfur diesel and jet fuel and LPGs (such as propane, butane and isobutane).

Our intermediate product pipelines consist of two parallel pipelines that originate at Holly’s Lovington, New Mexico refining facilities and terminate at Holly’s Artesia, New Mexico refining facilities. These pipelines transport intermediate feedstocks and crude oil for Holly’s refining operations in New Mexico.

Our pipelines are regularly inspected, are well maintained and we believe, are in good repair. Generally, other than as provided in the pipelines and terminal agreements with Holly and Alon, all of our pipelines are unrestricted as to the direction in which product flows and the types of refined products that we can transport on them. The FERC regulates the transportation tariffs for interstate shipments on our refined product pipelines and state regulatory agencies regulate the transportation tariffs for intrastate shipments on our pipelines.

The following table details the average aggregate daily number of barrels of petroleum products transported on our pipelines in each of the periods set forth below for Holly and for third parties.

		Years Ended December 31,
		2007				2006				2005(1)				2004				2003
Refined products transported for (bpd):
Holly			142,447				126,929				94,473				65,525				51,456
Third parties (2)			62,720				62,655				65,053				29,967				23,469
Total			205,167				189,584				159,526				95,492				74,925
Total barrels in thousands (“mbbls”)			74,886				69,198				58,227				34,950				27,348

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. Effective September 1, 2008, the leased capacity shall decrease to 17,500 barrels of refined product per day. Alon pays us whether or not it actually ships the full volumes of refined products it is entitled to ship. To the extent Alon does not use its capacity, we are entitled to use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of gasoline equivalent that may be transported in the existing configuration; in some cases, this includes the use of drag reducing agents.

						Approximate
		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

Holly shipped an aggregate of 55% of the petroleum products transported on our refined product pipelines and 100% of the petroleum products transported on our Intermediate Pipelines in 2007. These pipelines transported approximately 96% of the light refined products produced by Holly’s Navajo Refinery in 2007.

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 17% of the total light refined products produced at Holly’s Navajo Refinery during 2007. 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 2007, this pipeline transported to our El Paso terminal 55% 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, our pipeline also receives volumes of gasoline and diesel via a tie-in to our pipeline from Alon’s Big Spring, Texas refinery.

Artesia, New Mexico to Moriarty, New Mexico

The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline from Holly’s Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White Lakes Junction to Moriarty segment of this pipeline and the Moriarty to Bloomfield pipeline described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered into in 1996, which expires in 2017 and has two ten-year extensions at our option. At our Moriarty terminal, volumes shipped on this pipeline can be transported to other markets in the area, including Albuquerque, Santa Fe and west Texas, via tanker truck. The 155-mile White Lakes Junction to Moriarty segment of this pipeline is operated by Mid-America (or its designee). Holly is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to adjustments based on changes in the PPI) of $488,000 to Mid-America to lease the White Lakes Junction to Moriarty and Moriarty to Bloomfield pipelines.

Moriarty, New Mexico to Bloomfield, New Mexico

The Moriarty to Bloomfield refined product pipeline was constructed in 1973 and consists of 191 miles of 8-inch pipeline leased from Mid-America. This pipeline serves our terminal in Bloomfield. At our Bloomfield terminal, volumes shipped on this pipeline are transported to other markets in the Four Corners area via tanker truck. This pipeline is operated by Mid-America (or its designee). Holly is the only shipper on this pipeline.

Big Spring, Texas to Abilene, Texas

The Big Spring to Abilene refined product pipeline was constructed in 1957 and consists of 100 miles of 6-inch pipeline and 5 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery to the Abilene terminal. Alon is the only shipper on this pipeline.

Big Spring, Texas to Wichita Falls, Texas

Segments of the Big Spring to Wichita Falls refined product pipeline were constructed in 1969 and 1989, and consist of 95 miles of 6-inch pipeline and 132 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery to the Wichita Falls terminal. Alon is the only shipper on this pipeline.

Wichita Falls, Texas to Duncan, Oklahoma

The Wichita Falls to Duncan refined product pipeline is a common carrier and is regulated by the FERC. It was constructed in 1958 and consists of 47 miles of 6-inch pipeline. This pipeline is used for the shipment of refined products from the Wichita Falls terminal to Alon’s Duncan terminal, which we do not own. Alon is the only shipper on this pipeline.

Midland, Texas to Orla, Texas

Segments of the Midland to Orla refined product pipeline were constructed in 1928 and 1998, and consist of 50 miles of 10-inch pipeline and 85 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery from Midland to our tank farm at Orla. Alon is the only shipper on this pipeline.

8” Pipeline from Lovington, New Mexico to Artesia, New Mexico

The 65-mile 8-inch diameter pipeline was constructed in 1981. This pipeline is used for the shipment of intermediate feedstocks, crude oil and LPGs from Holly’s Lovington facility to its Artesia facility.

10” Pipeline from Lovington, New Mexico to Artesia, New Mexico

The 65-mile 10-inch diameter pipeline was constructed in 1999. This pipeline is used for the shipment of intermediate feedstocks and crude oil from Holly’s Lovington facility to its Artesia facility. Holly is the only shipper on this pipeline.

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 for $28.7 million. Currently, only LPG’s are transported on this pipeline, and BP is the only shipper. BP’s contract expires in April 2008. The contract provides that BP will ship a minimum average of 16,500 bpd during the term of the agreement. The tariff rates and shipping regulations are regulated by the FERC.

In January 2005, Rio Grande appointed us as operator of the pipeline system effective April 1, 2005 through January 31, 2010. 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.

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,
		2007				2006				2005(1)				2004				2003
Refined products terminalled for (bpd):
Holly			119,910				118,202				120,795				114,991				86,780
Third parties			45,457				43,285				42,334				24,821				19,956
Total			165,367				161,487				163,129				139,812				106,736
Total (mbbls)			60,359				58,943				59,542				51,171				38,959

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(1)

(barrels)

Tanks

Source

Mode of Delivery

El Paso, TX

507,000

16

Pipeline/ rail

Truck/Pipeline

Moriarty, NM

189,000

9

Pipeline

Truck

Bloomfield, NM

193,000

7

Pipeline

Truck

Tucson, AZ(2)

176,000

9

Pipeline

Truck

Mountain Home, ID(3)

120,000

3

Pipeline

Pipeline

Boise, ID(4)

111,000

9

Pipeline

Pipeline

Burley, ID(4)

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

2,181,000

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 68% of the volumes at this terminal. We also receive product from Alon’s Big Spring Refinery that accounted for 32% of the volumes at this terminal in 2007. Refined products received at this terminal are sold locally via the truck rack or transported to our Tucson terminal on Kinder Morgan’s East System pipeline. Competition in this market includes a refinery and terminal owned by Western Refining, Inc., a joint venture pipeline and terminal owned by ConocoPhillips and NuStar Energy, L.P. and a terminal connected to the Longhorn Pipeline.

Moriarty Terminal

We receive light refined products at this terminal from Holly’s Artesia facility through our pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly is our only customer at this terminal. There are no competing terminals in Moriarty.

Bloomfield Terminal

We receive light refined products at this terminal from Holly’s Artesia facility through our pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly is our only customer at this terminal. Competition in this market includes a refinery and truck loading rack owned by Western Refining, Inc.

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 NuStar pursuant to which we own 50% of the improvements on that parcel. On the other parcel, our joint venture with NuStar 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 NuStar 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 Transportation Company (“Sinclair”) each own a 50% interest in the Boise terminal. Sinclair is the operator of the terminal. The Boise terminal receives light refined products from Holly and Sinclair shipped through Chevron’s pipeline originating in Salt Lake City, Utah. The Woods Cross Refinery, as well as other refineries in the Salt Lake City area, and Pioneer Pipeline Co.’s terminal in Salt Lake City are connected to the Chevron pipeline. All loading of products out of the Boise terminal is conducted at Chevron’s loading rack, which is connected to the Boise terminal by pipeline. Holly and Sinclair are the only customers at this terminal.

Burley Terminal

We and Sinclair each own a 50% interest in the Burley terminal. Sinclair is the operator of the terminal. The Burley terminal receives product from Holly and Sinclair shipped through Chevron’s pipeline originating in Salt Lake City, Utah. Refined products received at this terminal are sold locally, via the truck rack. Holly and Sinclair are the only customers at this terminal.

Spokane Terminal

This terminal is connected to the Woods Cross Refinery via a Chevron common carrier pipeline. The Spokane terminal also is supplied by Chevron and Yellowstone pipelines and by rail and truck. Refined products received at this terminal are sold locally, via the truck rack. 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 2007. 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 2007. Refined products received at this terminal are sold via a truck rack or shipped via pipeline connections to Alon’s terminal in Duncan, Oklahoma and to NuStar’s Southlake pipeline. 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 2007. 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.

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 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 2007.

PART II

Item 5.		Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units

Our common limited partner units are traded on the New York Stock Exchange under the symbol “HEP.” The following table sets forth the range of the daily high and low sales prices per common unit, cash distributions to common unitholders and the trading volume of common units for the period indicated.

										Cash
Years Ended December 31,		High				Low				Distributions				Trading Volume
2007
Fourth Quarter		$	48.09			$	42.04			$	0.715				1,065,300
Third Quarter		$	57.24			$	43.10			$	0.705				1,273,100
Second Quarter		$	56.69			$	46.55			$	0.690				1,231,600
First Quarter		$	49.97			$	39.50			$	0.675				948,900
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

A distribution for the quarter ended December 31, 2007 of $0.725 per unit was paid on February 14, 2008.

As of February 7, 2008, we had approximately 4,620 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 prohibits us from making cash distributions under certain circumstances.

Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter: less the amount of cash reserves established by our general partner to provide for the proper conduct of our business; comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Upon the closing of our initial public offering, Holly received 7,000,000 subordinated units. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period 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 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.

We issued 937,500 of our Class B subordinated units in connection with the Alon transaction in 2005. The Class B subordinated units issued to Alon vote as a single class and rank equally with our existing subordinated units. There is a subordination period with respect to the Class B subordinated units with generally similar provisions to the subordinated units held by Holly, except that the subordination period will end on the last day of any quarter ending on or after March 31, 2010 if Alon has not defaulted on its minimum volume commitment payment obligations for the three consecutive, non-overlapping four quarter periods immediately preceding that date, subject to certain grace periods. If Holly is removed as the general partner without cause, the subordination period for the Class B subordinated units may end before March 31, 2010.

We make distributions of available cash from operating surplus for any quarter during any subordination period in the following manner: first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

The general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

						Marginal Percentage Interest in
		Total Quarterly Distribution				Distributions
		Target Amount				Unitholders				General Partner
Minimum Quarterly Distribution			$0.50				98	%			2	%
First Target Distribution		Up to $0.55					98	%			2	%
Second Target Distribution		above $0.55 up to $0.625					85	%			15	%
Third Target distribution		above $0.625 up to $0.75					75	%			25	%
Thereafter		Above $0.75					50	%			50	%

Item 6. Selected Financial Data

The following table shows selected financial information for HEP. This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of HEP and related notes thereto included elsewhere in this Form 10-K. See “Historical Results of Operations” below for a description of factors affecting the comparability of our financial information for years prior to 2005.

														2004
														Combined				Successor				Predecessor
																		July 13, 2004				January 1,
		Year Ended				Year Ended				Year Ended				Year Ended				Through				2004 Through				Year Ended
		December 31,				December 31,				December 31,				December 31,				December 31,				July 12,				December 31,
		2007				2006				2005				2004(1)				2004				2004				2003
		(In thousands, except per unit data)
Statement Of Income Data:
Revenue		$	105,407			$	89,194			$	80,120			$	67,766			$	28,182			$	39,584			$	30,800
Operating costs and expenses
Operations			32,911				28,630				25,332				23,641				10,104				13,537				24,193
Depreciation and amortization			14,382				15,330				14,201				7,224				3,241				3,983				6,453
General and administrative			5,043				4,854				4,047				1,860				1,859				1				—
			52,336				48,814				43,580				32,725				15,204				17,521				30,646
Operating income			53,071				40,380				36,540				35,041				12,978				22,063				154
Interest income			533				899				649				144				65				79				291
Interest expense			(13,289	)			(13,056	)			(9,633	)			(697	)			(697	)			—				—
Gain on sale of assets			298				—				—				—				—				—				—
Equity in earnings of Rio Grande Pipeline Company			—				—				—				—				—				—				894
			(12,458	)			(12,157	)			(8,984	)			(553	)			(632	)			79				1,185
Income before minority interest			40,613				28,223				27,556				34,488				12,346				22,142				1,339
Minority interest in Rio Grande Pipeline Company			(1,067	)			(680	)			(740	)			(1,994	)			(956	)			(1,038	)			(758	)
Income before income taxes			39,546				27,543				26,816				32,494				11,390				21,104				581
State income tax			(275	)			—				—				—				—				—				—
Net income			39,271				27,543				26,816				32,494				11,390				21,104				581
Less:
Net income attributable to Predecessor			—				—				—				21,104				—				21,104				581
General partner interest in net income			2,932				1,710				721				228				228				—				—
Limited partners’ interest in net income		$	36,339			$	25,833			$	26,095			$	11,162			$	11,162			$	—			$	—
Net income per limited partner unit – basic and diluted		$	2.26			$	1.60			$	1.70							$	0.80
Cash distributions declared per unit applicable to limited partners		$	2.785			$	2.585			$	2.225							$	0.435
Other Financial Data:
EBITDA (2)		$	66,684			$	55,030			$	50,001			$	40,271			$	15,263			$	25,008			$	6,743
Cash flows from operating activities		$	59,056			$	45,853			$	42,628			$	15,867			$	15,371			$	496			$	5,909
Cash flows from investing activities		$	(9,632	)		$	(9,107	)		$	(131,795	)		$	(2,977	)		$	(305	)		$	(2,672	)		$	(27,947	)
Cash flows from financing activities		$	(50,658	)		$	(45,774	)		$	90,646			$	(480	)		$	1,770			$	(2,250	)		$	28,372
Maintenance capital expenditures (3)		$	1,863			$	1,095			$	364			$	1,197			$	305			$	892			$	1,934
Expansion capital expenditures			8,094				8,012				3,519				1,780				—				1,780				4,837
Total capital expenditures		$	9,957			$	9,107			$	3,883			$	2,977			$	305			$	2,672			$	6,771
Balance Sheet Data (at period end):
Net property, plant and equipment		$	158,600			$	160,484			$	162,298			$	74,626			$	74,626			$	95,337			$	95,826
Total assets		$	238,904			$	245,771			$	254,775			$	103,758			$	103,758			$	156,373			$	140,425
Long-term debt		$	181,435			$	180,660			$	180,737			$	25,000			$	25,000			$	—			$	—
Total liabilities		$	200,348			$	198,582			$	190,962			$	28,998			$	28,998			$	53,146			$	57,089
Net partners’ equity (4)		$	27,816			$	36,226			$	52,060			$	61,528			$	61,528			$	89,964			$	68,860

														2004
														Combined				Successor				Predecessor
																		July 13,
																		2004				January 1,				Year
		Year Ended				Year Ended				Year Ended				Year Ended				Through				2004 Through				Ended
		December				December				December				December				December				July				December
		31, 2007				31, 2006				31, 2005				31, 2004				31, 2004				12, 2004				31, 2003
		(In thousands)
Net income		$	39,271			$	27,543			$	26,816			$	32,494			$	11,390			$	21,104			$	581
Add depreciation and amortization			14,382				15,330				14,201				7,224				3,241				3,983				6,453
Add state income tax			275				—				—				—				—				—				—
Add interest expense			13,289				13,056				9,633				697				697				—				—
Subtract interest income			(533	)			(899	)			(649	)			(144	)			(65	)			(79	)			(291	)
EBITDA		$	66,684			$	55,030			$	50,001			$	40,271			$	15,263			$	25,008			$	6,743

Historical Results of Operations

In reviewing the historical results of operations that are presented above, 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;
	•		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.

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
•		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 on July 13, 2004 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.

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. We 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, Idaho and Arizona and a 70% interest in Rio Grande. HEP is currently 45% owned by Holly.

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.

Agreements with Holly

We serve Holly’s refineries in New Mexico and Utah under two 15-year pipeline and terminal agreements. The Holly PTA relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019. The Holly IPA relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020. The substantial majority of our business is devoted to providing transportation and terminalling services to Holly. Following the July 1, 2007 rate adjustment for the PPI, the volume commitment by Holly under the Holly PTA will produce at least $39.6 million of revenue for the twelve months ending June 30, 2008. Under the Holly IPA, Holly agreed to transport volumes of intermediate products on the intermediate pipelines that following the July 1, 2007 PPI adjustment will result in minimum funds to us of $12.8 million for the twelve months ended June 30, 2008. If Holly fails to meet its minimum volume commitments 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.

In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete this project by January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008, on Holly shipments on our refined product pipelines.

Under the Omnibus Agreement, we pay Holly an annual administrative fee, initially $2.0 million for each of the three years following the closing of our initial public offering, for the provision by Holly or its affiliates of various general and administrative services to us. Effective July 1, 2007, the annual fee increased to $2.1 million in accordance with provisions under the agreement. This fee does not include the salaries of

pipeline and terminal personnel or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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, 2007, 2006 and 2005.

		Year Ended
		December 31,								Change from
		2007				2006				2006
		(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines		$	36,281			$	31,723			$	4,558
Third parties – refined product pipelines			36,271				31,685				4,586
			72,552				63,408				9,144
Affiliates – intermediate pipelines			13,731				10,733				2,998
			86,283				74,141				12,142
Terminals and truck loading racks:
Affiliates			10,949				10,422				527
Third parties			5,427				4,631				796
			16,376				15,053				1,323
Other — affiliates			2,748				—				2,748
Total revenues			105,407				89,194				16,213
Operating costs and expenses
Operations			32,911				28,630				4,281
Depreciation and amortization			14,382				15,330				(948	)
General and administrative			5,043				4,854				189
			52,336				48,814				3,522
Operating income			53,071				40,380				12,691
Interest income			533				899				(366	)
Interest expense, including amortization			(13,289	)			(13,056	)			(233	)
Gain on sale of assets			298				—				298
Minority interest in Rio Grande Pipeline Company			(1,067	)			(680	)			(387	)
			(13,525	)			(12,837	)			(688	)
Income before income taxes			39,546				27,543				12,003
State income tax			(275	)			—				(275	)
Net income			39,271				27,543				11,728
Less general partner interest in net income, including incentive distributions (1)			2,932				1,710				1,222
Limited partners’ interest in net income		$	36,339			$	25,833			$	10,506
Net income per unit applicable to limited partners (1)		$	2.26			$	1.60			$	0.66
Weighted average limited partners’ units outstanding			16,108				16,108				—
EBITDA(2)		$	66,684			$	55,030			$	11,654
Distributable cash flow (3)		$	51,012			$	47,219			$	3,793
Volumes (bpd)(4)
Pipelines:
Affiliates – refined product pipelines			77,441				69,271				8,170
Third parties – refined product pipelines			62,720				62,655				65
			140,161				131,926				8,235
Affiliates – intermediate pipelines			65,006				57,658				7,348
			205,167				189,584				15,583
Terminals and truck loading racks:
Affiliates			119,910				118,202				1,708
Third parties			45,457				43,285				2,172
			165,367				161,487				3,880
Total for petroleum pipelines and terminal assets (bpd)			370,534				351,071				19,463

		Year Ended
		December 31,								Change from
		2006				2005				2005
		(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines		$	31,723			$	29,288			$	2,435
Third parties – refined product pipelines			31,685				31,447				238
			63,408				60,735				2,673
Affiliates – intermediate pipelines			10,733				4,643				6,090
			74,141				65,378				8,763
Terminals and truck loading racks:
Affiliates			10,422				10,253				169
Third parties			4,631				4,489				142
			15,053				14,742				311
Total revenues			89,194				80,120				9,074
Operating costs and expenses
Operations			28,630				25,332				3,298
Depreciation and amortization			15,330				14,201				1,129
General and administrative			4,854				4,047				807
			48,814				43,580				5,234
Operating income			40,380				36,540				3,840
Interest income			899				649				250
Interest expense, including amortization			(13,056	)			(9,633	)			(3,423	)
Minority interest in Rio Grande Pipeline Company			(680	)			(740	)			60
			(12,837	)			(9,724	)			(3,113	)
Net income			27,543				26,816				727
Less general partner interest in net income, including incentive distributions (1)			1,710				721				989
Limited partners’ interest in net income		$	25,833			$	26,095			$	(262	)
Net income per unit applicable to limited partners (1)		$	1.60			$	1.70			$	(0.10	)
Weighted average limited partners’ units outstanding			16,108				15,356				752
EBITDA(2)		$	55,030			$	50,001			$	5,029
Distributable cash flow (3)		$	47,219			$	41,438			$	5,781
Volumes (bpd)(4)
Pipelines:
Affiliates – refined product pipelines			69,271				66,206				3,065
Third parties – refined product pipelines			62,655				65,053				(2,398	)
			131,926				131,259				667
Affiliates – intermediate pipelines			57,658				28,267				29,391
			189,584				159,526				30,058
Terminals and truck loading racks:
Affiliates			118,202				120,795				(2,593	)
Third parties			43,285				42,334				951
			161,487				163,129				(1,642	)
Total for petroleum pipelines and terminal assets (bpd)			351,071				322,655				28,416