HOLLY ENERGY PARTNERS LP - Annual Report: 2004 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

Commission File Number 1-32225

HOLLY ENERGY PARTNERS, L.P.

I.R.S. Employer Identification No. 20-0833098

100 Crescent Court, Suite 1600
Dallas, Texas 75201
Telephone Number: (214) 871-3555

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

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

Indicate by check mark whether the registrant (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 an accelerated filer (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 $274 million on February 18, 2005, 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 18, 2005 was 7,000,000.

DOCUMENTS INCORPORATED BY REFERENCE: None

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TABLE OF CONTENTS

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PART I

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business and Properties” in Items 1 and 2 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:

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 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Items 1 & 2. Business and Properties

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership formed by Holly Corporation (“Holly”) 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 75201-6927. 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 Controller 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 Controller 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.

On March 15, 2004, we filed a Registration Statement on Form S-1 with the United States Securities and Exchange Commission (the “SEC”) relating to a proposed underwritten initial public offering of limited partnership units in HEP. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). On July 7, 2004, we priced 6,100,000 common units for the initial public offering and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $145.5 million, net of $10.3 million underwriting commissions. All the initial assets of HEP were contributed by Holly and its subsidiaries in exchange for a) 7,000,000 subordinated units, representing a 49% limited partner interest in HEP, b) incentive distribution rights (as discussed in Part II, Item 5 — Market for the Registrant’s Common Units and Related Unitholder Matters), c) the 2% general partner interest, and d) an aggregate cash distribution of $125.6 million. The operating subsidiary of HEP, Holly Energy Partners — Operating, L.P., formed in anticipation of the HEP public offering, entered into a four-year $100 million revolving credit agreement with Union Bank of California, as administrative agent and a lender, in conjunction with the initial public offering, with an option to increase the amount to $175 million under certain conditions. At closing of the initial public offering, $25 million was drawn under the facility. The proceeds of the public offering and the $25 million borrowing were used to: establish $9.9 million working capital for HEP, distribute $125.6 million to Holly, repay $30.1 million of short-term debt to Holly, pay $13.8 million underwriting commissions and other offering costs, and pay $1.4 million of deferred debt issuance costs related to the revolving credit agreement.

We generate revenues by charging tariffs for transporting refined 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 and therefore we are not directly exposed to changes in commodity prices. We serve Holly’s refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement with Holly (“Pipelines and Terminals Agreement”) expiring 2019. Our assets include:

     Refined Product Pipelines:

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     Refined Product Terminals:

In addition, we have an option to purchase two intermediate product pipelines from Holly. These pipelines transport crude oil and feedstocks from Holly’s Lovington facility to its Artesia facility. These pipelines are each 65 miles long and have a current aggregate throughput capacity of 84,000 bpd.

Our pipelines transport light refined products (gasoline, diesel and jet fuel) from Holly’s Navajo Refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah, Idaho, Washington and northern Mexico. We also transport gasoline and diesel fuel for Alon USA, Inc. from Orla, Texas to El Paso, Texas under three long-term capacity lease arrangements. The substantial majority of our business is devoted to providing transportation and terminalling services to Holly. We operate our business as one business segment.

On January 25, 2005, we entered into a contribution agreement with Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) that provides for our acquisition, subject to the terms and conditions of the agreement, of four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas. These pipelines and terminals transport approximately 70% of the light refined products for Alon’s 65,000 bpd capacity refinery in Big Spring, Texas. The total consideration for these pipeline and terminal assets is $120 million in cash and 937,500 of our Class B subordinated units. In connection with the transaction, we will enter into a 15-year pipelines and terminals agreement with Alon. The Alon transaction is expected to close on or about February 28, 2005. Please read “The Pending Alon Transaction” on page 19 for additional information.

Historical Results of Operations

The financial statements and financial information for the years ended December 31, 2004, 2003 and 2002 reflect the operations of HEP from July 13, 2004, and NPL, the predecessor to HEP, for all periods prior to July 13, 2004. HEP commenced operations on July 13, 2004 upon completion of our initial public offering of limited partner interests and the concurrent contribution of most of the operating assets of the predecessor business to HEP.

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

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

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

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

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 our “Pipelines and Terminals Agreement” described below.

In addition, our historical results of operations reflect the impact of the following acquisitions completed in June 2003:

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.

Our Relationship with Holly

The majority of our business is devoted to providing transportation and terminalling services to Holly, an independent petroleum refiner and marketer that produces high value light products such as gasoline, diesel fuel and jet fuel. For the year ended December 31, 2004, Holly accounted for $45.3 million or 66.9%, of our revenues. We expect to continue to derive a majority of our revenues from Holly for the foreseeable future. Holly has a significant interest in our partnership through its indirect ownership of a 49% limited partner interest (before we issue the Class B Subordinated Units to Alon) and a 2% general partner interest. Holly currently markets the light refined products it produces in Texas, New Mexico, Arizona, Montana, Utah, Colorado, Idaho, Washington, and northern Mexico.

Holly owns and operates the Navajo Refinery, the largest refinery in New Mexico, consisting of refining facilities that are located 65 miles apart in Artesia and Lovington and operated in conjunction with each other. We believe the Navajo Refinery, which has operated continuously since its acquisition by Holly in 1969, is one of the most efficient and technologically advanced refineries in the geographic area it serves, with a Nelson complexity Index rating of 10.0. In December 2003, Holly completed at an approximate cost of $85.0 million a gasoil hydrotreater and expansion project at the Artesia facility that increased its crude oil processing capacity from 60,000 bpd to 75,000 bpd and allowed the refinery to meet or exceed the federally mandated clean air requirements for gasoline. The majority of our operations are located

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within Holly’s New Mexico refining market area. Holly relies on us to provide almost all of the light refined product transportation and terminalling services it requires to support its New Mexico refining operations. For the year ended December 31, 2004, we transported and terminalled 99% of the light refined products produced by the Navajo Refinery. In addition, Holly is currently evaluating further expansion of the Navajo Refinery up to a capacity of 85,000 bpd, substantially all of which we believe would be shipped on our pipelines.

Holly also operates a crude oil refinery in Woods Cross, Utah, near Salt Lake City, primarily serving markets in Utah and Idaho. The Woods Cross Refinery has a current crude oil processing capacity of 25,000 bpd and, for the year ended December 31, 2004, it processed 23,620 bpd of crude oil utilizing 94.5% of the refinery’s capacity. We terminalled 100% of the light refined products produced by the Woods Cross Refinery.

Pipelines and Terminals Agreement

We have a 15-year Pipelines and Terminals Agreement with Holly expiring 2019. Under this agreement, Holly will pay us fees that we believe are comparable to those that would be charged by third parties. Holly also agreed to transport on our refined product pipelines and throughput in our terminals a volume of refined products that will result in minimum revenues of $35.4 million in the first year. This minimum revenue commitment will increase each year at a rate equal to the percentage change in the producer price index, but will not decrease as a result of a decrease in the producer price index. Holly will pay the published tariff rates on the pipelines and contractually agreed upon fees at the terminals. The tariffs will adjust annually at a rate equal to the change in the producer price index. The terminal fees will adjust annually based upon an index comprised of comparable fees posted by third parties. Holly’s minimum revenue commitment applies only to our initial assets and may not be spread among assets we subsequently acquire. If Holly fails to meet its minimum revenue commitment in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met.

At Holly’s request, we will use our best efforts to transport by pipeline each month during the term of the agreement up to 40,000 bpd from Artesia to El Paso and up to 40,000 bpd from Artesia to Moriarty/Bloomfield, subject to our common carrier duty to pro-ration capacity, where applicable. We have also agreed to provide terminalling services for all of Holly’s barrels shipped on those pipelines to those destinations.

Holly’s obligations under this agreement may be proportionately reduced or suspended if Holly (1) shuts down or reconfigures one of its refineries (other than for planned maintenance turnarounds) and (2) reasonably believes in good faith that such event will jeopardize its ability to satisfy its minimum revenue obligations. Holly must give at least twelve month’s advance notice of any long-term shutdown or material reconfiguration. Holly will propose new minimum obligations that proportionally reduce the affected obligations. If we do not agree with this reduction, any change in Holly’s obligations will be determined by binding arbitration.

Furthermore, if new laws or regulations that affect terminals or pipelines generally are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right to impose 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 for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly’s pro rata portion of the cost of complying with these laws or regulations, after we have made efforts to mitigate their effect. We and Holly will negotiate in good faith to agree on the level of the monthly surcharge or increased tariff rate.

Holly’s obligations under this agreement may be temporarily suspended during the occurrence of an event that is outside the control of the parties that renders performance impossible with respect to an asset for at least 30 days. An event with a duration of longer than one year would allow us or Holly to terminate the contract.

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Holly has business interruption insurance for the benefit of its refinery assets. Payments Holly is required to make pursuant to its minimum revenue commitment would be recoverable to Holly under its policy in the event of an insurable loss at its facilities. In addition, we maintain our own business interruption insurance for the benefit of our pipelines and terminals, that would allow us to recover losses due to interruption at our customers’ facilities that affect our revenue.

Holly has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates for the term of the Pipelines and Terminals Agreement. This agreement does not prevent other current or future shippers from challenging our tariff rates. At the end of the agreement, Holly will be free to challenge, or to cause others to challenge or assist others in challenging, our tariff rates.

During the term of the agreement, we have agreed not to reverse the direction of any of our pipelines or to connect any other pipelines to our pipelines or terminals without the consent of Holly.

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

Upon termination of the agreement, Holly will have a limited right of first refusal giving it the right to enter into a new Pipelines and Terminals Agreement with us pursuant to which Holly will agree to match any commercial terms offered to us by a third party.

To the extent Holly does not extend or renew the Pipelines and Terminals Agreement, our financial condition and results of operations may be adversely affected. The majority of our assets were constructed or purchased to service Holly’s needs. As a result, we would expect that even if this agreement were not renewed, Holly would continue to use our pipelines and terminals. However, we cannot assure you that Holly will continue to use our facilities or that we will be able to generate additional revenue from third parties.

From time to time Holly considers changes to its refineries. Those changes may involve new facilities, reduction in certain operations or modifications of facilities or operations. Changes may be considered to meet market demands, to satisfy regulatory requirements or environmental and safety objectives, to improve operational efficiency or for other reasons. One such project recently completed is an approximate $85.0 million gasoil hydrotreater and expansion project at Holly’s Artesia facility that expanded total crude oil processing capacity from 60,000 bpd to 75,000 bpd and allowed the refinery to meet or exceed current federally mandated clean air requirements for gasoline.

Holly has advised us that although it continually considers the types of matters referred to above, it currently does not intend to close or dispose of the refineries currently served by our pipelines and terminals or to cause any changes that would have a material adverse effect on us. Holly is, however, actively managing its assets and operations, and, therefore, changes of some nature, possibly material to us, are likely to occur at some point in the future.

PIPELINES

Overview

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

Our refined product pipelines were originally constructed between 1981 and 1999, except for the Artesia to El Paso pipeline, which was originally constructed in 1959. Our pipelines are regularly inspected and are well maintained, and we believe they are in good repair. Generally, other than as provided in the

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Pipelines and Terminals Agreement, all of our pipelines are unrestricted as to the direction in which product flows and the type 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 refined products transported on our refined product pipelines in each of the periods set forth below for Holly and for third parties.

The following table sets forth certain operating data for each of our refined product pipelines. Except as shown below, we own 100% of our refined product pipelines. Throughput is the total average number of barrels per day transported on a pipeline, but does not aggregate barrels moved between different points on the same pipeline. Revenues reflect tariff revenues generated by barrels shipped from an origin to a delivery point on a pipeline. Revenues also include payments made by Alon under capacity lease arrangements on our Orla to El Paso pipeline. Under these arrangements, we provide space on our pipeline for the shipment of up to 20,000 barrels of refined product per day. Alon pays us whether or not it actually ships the full volumes of refined products it is entitled to ship. To the extent Alon does not use its capacity, we are entitled to use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of gasoline equivalent that may be transported in the existing configuration; in some cases, this includes the use of drag reducing agents.

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For the years ended December 31, 2004 and 2003, Holly accounted for an aggregate of 83.7% and 78.3%, respectively, of the refined product volumes transported on our refined product pipelines (excluding the Rio Grande Pipeline). For the same periods, these pipelines transported approximately 99% of the light refined products transported by pipeline from Holly’s Navajo Refinery.

Refined Product Pipelines

Artesia, New Mexico to El Paso, Texas
The Artesia to El Paso refined product pipeline 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 17.2% of the total light refined products produced at Holly’s Navajo Refinery during 2003 and 18.1% of the total light refined products produced during 2004. 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:

There are two shippers on this pipeline, Holly and Alon. In 2003 and 2004, this pipeline transported to our El Paso terminal 47.4% and 44.8%, respectively of the light refined products produced at Holly’s Navajo Refinery. During 2003 and 2004, 31,000 bpd and 38,000 bpd, respectively, of the product we transported for Holly was delivered to third-party pipelines from our El Paso terminal for further transportation to Arizona, northern New Mexico and northern Mexico; the balance of the product is distributed through the terminal’s truck rack for further delivery by tanker truck.

At Orla, the pipeline received volumes of gasoline and diesel from Alon’s 65,000 bpd Big Spring, Texas refinery through a tie-in to an Alon pipeline system. Alon has reserved an aggregate of 20,000 bpd of capacity on the segment of our pipeline from Orla to El Paso under a lease agreement providing for three separate long-term capacity lease arrangements, the earliest of which expires in August 2008. Each of these lease arrangements provides for five-year extension options at Alon’s option. Under these arrangements, Alon pays us for this capacity, without regard to the volumes of refined products it actually ships.

Holly accounted for 64.5% and Alon accounted for 35.5% of volumes transported on this pipeline for the year ended December 31, 2003. For the same period, Holly accounted for 61.0% of the revenues generated by this pipeline and Alon accounted for 39.0%. For 2004, Holly accounted for 71.3% of the volumes and 64.9% of the revenues for this pipeline, with Alon accounting for the balance.

Artesia, New Mexico to Moriarty, New Mexico
The Artesia to Moriarty refined product pipeline consists of a 59.5-mile, 12-inch pipeline from Holly’s Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White Lakes Junction to Moriarty segment of this pipeline and our Moriarty to Bloomfield pipeline described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered into in 1996, which expires in 2007 and has

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one ten-year extension at our option. At our Moriarty terminal, volumes shipped on this pipeline can be transported to other markets in the area, including Albuquerque, Santa Fe and west Texas, via tanker truck. The 155-mile White Lakes Junction to Moriarty segment of this pipeline is operated by Mid-America Pipeline Company, LLC (or its designee). Holly is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to adjustments based on changes in the producer price index) of $455,000 to Mid-America Pipeline Company, LLC to lease the White Lakes Junction to Moriarty and Moriarty to Bloomfield pipelines.

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

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 Plc (“BP”). The pipeline originates from a connection with an Enterprise pipeline in west Texas at Lawson Junction, and terminates at the Mexican border near San Elizario, Texas, with a delivery point and an additional receipt point near Midland, Texas, for ultimate use by PEMEX (the government-owned energy company of Mexico). Rio Grande does not own any facilities or pipelines in Mexico. The pipeline has a current capacity of approximately 27,000 bpd. This pipeline was originally constructed in the mid 1950’s, was first reconditioned in 1988, and subsequently reconditioned in 1996 and 2003. Approximately 75 miles of this pipeline has been replaced with new pipe, and an additional 50 miles has been recoated.

Rio Grande was formed in 1996, at which time we contributed nearly 220 miles of pipeline from near Odessa, Texas to outside El Paso, Texas in exchange for a 25% interest in the joint venture. Rio Grande Pipeline began operations in 1997. In June 2003, we acquired an additional 45% interest in the joint venture from Juarez Pipeline Co., an affiliate of The Williams Companies, Inc. for $28.7 million. The pipeline has recently completed a reconditioning project that could facilitate an expansion to 32,000 bpd. Currently, only LPG’s are transported on this pipeline, and BP is the only shipper. BP’s contract provides that BP will ship a minimum average of 16,500 bpd for the duration of the agreement. The tariff rates and shipping regulations are regulated by the FERC. For the years ended December 31, 2002, 2003 and 2004, including a border crossing fee, BP paid $14.2 million, $13.5 million and $12.4 million, respectively, pursuant to its contract. During the first quarter of 2005 based on the aggregate volumes shipped by BP, we expect that BP will no longer be required to pay the border crossing fee pursuant to its contract. For the year ended December 31, 2004, the border crossing fee paid by BP to Rio Grande was $4.5 million.

In January 2005, Rio Grande appointed us as operator of the pipeline system effective April 1, 2005 through January 31, 2010. We agreed to pay $745,000 to the current operator as an inducement to and consideration for its early resignation. This payment will be made in the first quarter of 2005. As operator, we will receive a management fee of $900,000 per year, adjusted annually for any changes in the producer price index.

An officer of Holly Logistic Services, L.L.C., a subsidiary of Holly, is one of the two members of Rio Grande’s management committee.

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REFINED PRODUCT TERMINALS

Our refined product terminals receive products from pipelines and Holly’s Navajo and Woods Cross refineries and 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 marketing activities. Terminals play a key role in moving product to the end-user market by providing the following services:

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.

For the year ended December 31, 2004, gasoline represented 64% of the total volume of refined products distributed through our product terminals, while distillates represented 36%.

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

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The following table outlines the locations of our terminals and their storage capacities, number of tanks, supply source, mode of delivery and average throughput (in bpd) for the period presented:

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 78% of the volumes at this terminal. We also receive product from Alon’s Big Spring, Texas refinery that accounted for 22% of the volumes at this terminal in 2004. Refined products received at this terminal are sold locally via the truck rack, transported to our Tucson terminal on Kinder Morgan Energy partners L.P.’s East System pipeline or to our Albuquerque terminal on Chevron Texaco’s Juarez pipeline. Competition in this market includes a refinery and terminal owned by Western Refining, a joint venture pipeline and terminal owned by ConocoPhillips and Valero, L.P. and a terminal connected to the Longhorn Pipeline that is currently inactive.

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

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

Albuquerque Terminal
We receive light refined products from Holly that are transported on Chevron Texaco’s Albuquerque pipeline from our El Paso terminal and account for over 90% of the volumes at this terminal. We also receive product from ConocoPhillips and Valero, L.P. that are transported to the Albuquerque terminal on

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Valero, L.P.’s West Emerald pipeline from its McKee, Texas refinery. Refined products received at this terminal are sold locally, via the truck rack. Competition in the Albuquerque market includes terminals owned by ChevronTexaco, ConocoPhillips, Giant and Valero. We and ConocoPhillips each owned a 50% interest in the Albuquerque terminal through July 2004 at which time we acquired the 50% interest owned by ConocoPhillips.

Tucson Terminal
The Tucson terminal consists of two parcels. On one parcel, we lease the underlying ground as a 50% co-tenant with a division of Kaneb pursuant to which we own 50% of the improvements on that parcel. On the other parcel, our joint venture with Kaneb 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 Kaneb 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 ChevronTexaco’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 Department of Fuel Supply Standard, for injecting, storing, testing and transporting jet fuel at this terminal.

Boise Terminal
We and Sinclair each own a 50% interest in the Boise terminal. Sinclair is the operator of the terminal. The Boise terminal receives light refined products from Holly and Sinclair shipped through ChevronTexaco’s pipeline originating in Salt Lake City, Utah. The Woods Cross Refinery, as well as other refineries in the Salt Lake City area, and Pioneer’s terminal in Salt Lake City are connected to the ChevronTexaco pipeline. All loading of products out of the Boise terminal is conducted at ChevronTexaco’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 ChevronTexaco’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 ChevronTexaco common carrier pipeline. The Spokane terminal also is supplied by ChevronTexaco and Yellowstone pipelines and by rail and truck. Refined products received at this terminal are sold locally, via the truck rack. Shell, ChevronTexaco and Holly are the major customers at this terminal. Other terminals in the Spokane area include terminals owned by ExxonMobil and ConocoPhillips.

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.

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PIPELINE AND TERMINAL CONTROL OPERATIONS

All of our existing pipelines are operated via geosynchronous satellite, microwave, radio and frame relay communication systems from a central control room located in Artesia, New Mexico. We also monitor activity at our terminals from this control room.

The control center operates with modern, state-of-the-art System Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points on the pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces our requirement for full-time on-site personnel at most of these locations.

The assets being acquired from Alon will be operated from a control room located in Big Spring, Texas.

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.

Our capital requirements have historically been met with internally generated funds including short-term non-interest bearing funding from affiliates. We have budgeted $1.5 million maintenance capital expenditures for our existing operations in 2005 (excluding approximately $0.5 million of maintenance capital expenditures we anticipate with respect to assets to be acquired in the pending Alon transaction). We anticipate that these capital expenditures will be funded with cash generated by operations. However, we may fund future expansion capital requirements or acquisitions through long-term borrowings or other debt financings and/or equity capital offerings.

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

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approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. 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. Since 1998, we have inspected approximately 98% of the total miles of our pipelines. We anticipate spending approximately $250,000 per year to comply with these new inspection regulations.

Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state, and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT, and accepted industry practice.

At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.

Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals are subject to participation in a comprehensive environmental management program to assure compliance with applicable air, solid waste, and wastewater regulations.

COMPETITION

As a result of our physical integration with Holly’s Navajo Refinery and our contractual relationship with Holly under the omnibus agreement (the “Omnibus Agreement”) and the Pipelines and Terminals Agreement, 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 Pipelines and Terminals Agreement with Holly expiring in 2019.

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

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

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

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Historically, the vast majority of the throughput at our terminal facilities, other than third-party receipts at the Spokane terminal and Alon volumes at El Paso, has come from Holly. Under the terms of our Pipelines and Terminals Agreement, we continue to receive a significant portion of the throughput at these facilities from Holly.

Our nine 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.

OPTION TO PURCHASE INTERMEDIATE PRODUCT PIPELINES

In connection with our initial public offering, Holly granted us an exclusive three-year option to purchase its intermediate product pipelines at fair market value at the time of purchase. The pipelines transport feedstocks and crude oil from Holly’s Lovington crude oil processing unit to its downstream processing unit in the Artesia facility. The Lovington to Artesia 8-inch pipeline and the Lovington to Artesia 10-inch pipeline both originate at Holly’s Lovington facility and terminate at its Artesia facility. Each pipeline is 65 miles long. Holly did not contribute these pipelines to our partnership because, unlike our other pipelines which transport refined products from Holly’s refineries to its customers, the Lovington to Artesia pipelines transport feedstocks and crude oil only between two Holly refining facilities.

In the event we exercise our option, we would anticipate entering into a throughput agreement containing a minimum revenue commitment with Holly with respect to those pipelines generally consistent with the terms contained in the Pipelines and Terminals Agreement. The option is contained in the Omnibus Agreement with Holly. Under this agreement, if we decide to exercise our option, we have the right to provide written notice to Holly setting forth the fair market value we propose to pay for the intermediate product pipelines. If Holly does not agree with our proposed fair market value, we and Holly may appoint a mutually agreed-upon investment banking firm to determine the fair market value. Once the investment bank submits its valuation, we will have the right, but not the obligation, to purchase the asset at the price determined by the investment bank.

RATE REGULATION

Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and non-discriminatory. The Interstate Commerce Act permits challenges to proposed new or changed rates by protest, and challenges to rates that are already on file and in effect by complaint. Upon the appropriate showing, a successful complainant may obtain damages or reparations for generally up to two years prior to the filing of a complaint. The FERC generally has not investigated interstate rates on its own initiative when those rates, like ours, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate any new interstate rates we might file if those rates were protested by a third party and the third party were able to show that it had a substantial economic interest in our tariff rate level. The FERC could also investigate any of our existing interstate rates if a complaint were filed against the rate.

While the FERC regulates the rates for interstate shipments on our refined product pipelines, the New Mexico Public Regulation Commission regulates the rates for intrastate shipments in New Mexico, the Texas Railroad Commission regulates the rates for intrastate shipments in Texas, and the Idaho Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints, and we do not believe the intrastate tariffs now in effect are likely to be challenged. A state regulatory commission could, however, investigate our rates if such a challenge were filed.

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ENVIRONMENTAL REGULATION AND REMEDIATION

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

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

Holly has agreed to indemnify us in an aggregate amount not to exceed $15 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 transferred to us and occurring or existing before that date.

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.

An environmental remediation project is in progress currently at our El Paso terminal; the remaining costs of which are projected to be approximately $0.8 million over the next five years. Other parties are undertaking remediation projects at our Boise, Burley and Albuquerque terminals, and we are obligated to pay a portion of these costs at the Albuquerque terminal, but not at the Boise or Burley terminals. The estimated cost for our share of the environmental remediation at the Albuquerque terminal is approximately $0.3 million, to be incurred over the next five years. Holly has agreed, subject to a $15 million limit, to indemnify us for environmental liabilities related to the assets transferred to us to the extent such liabilities exist or arise 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. This indemnity will cover the costs associated with performance of the assessment, monitoring, and remediation programs, including the remediation projects at El Paso and Albuquerque.

We may experience future releases of refined products into the environment from our pipelines and terminals, or discover historical releases that were previously unidentified or not assessed. While 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, Holly Logistic Services, L.L.C., a subsidiary of Holly, employs 73 people who provide direct support to our operations. None of these employees are covered by collective bargaining agreements. Holly Logistic Services, L.L.C. considers its employee relations to be good. Neither we nor

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our general partner have employees. We reimburse Holly for direct expenses they incur on our behalf for the employees of Holly Logistic Services, L.L.C.

PENDING ALON TRANSACTION

On January 25, 2005, we entered into a contribution agreement with Alon that provides for our acquisition, subject to the terms and conditions of the agreement, of four refined products pipelines aggregating approximately 500 miles, an associated tank farm and two refined products terminals with aggregate storage capacity of approximately 347,000 barrels. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s 65,000 bpd capacity refinery in Big Spring, Texas.

The total consideration for these pipeline and terminal assets will be $120 million in cash and 937,500 of our Class B subordinated units. We anticipate financing the pending Alon transaction through our private offering of $150 million principal amount of 6.25% senior notes previously announced on February 4, 2005 and priced on February 11, 2005. We expect to issue the notes and close the offering and the Alon transaction on or about February 28, 2005.

In connection with the Alon transaction, we will enter into a 15-year pipelines and terminals agreement with Alon. Under this agreement, Alon will agree to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to us of $20.2 million per year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipeline and terminals taking into account a 5,000 BPD expansion of Alon’s Big Spring Refinery expected to be completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. We will grant Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have a right of first refusal to purchase the pipelines and terminals if we decide to sell them in the future. Additionally, we will enter into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals to be acquired from Alon, where Alon will indemnify us subject to a $100,000 deductible and a $20 million maximum liability cap.

We do not expect to be required to develop or acquire any additional assets in order to operate the pipelines and terminals to be acquired from Alon or in order to integrate them into our existing operations. With appropriate maintenance, we believe that the assets to be acquired from Alon will have a remaining useful life for accounting purposes of at least 15 years. Our management believes that the operating expenses for the Alon pipelines and terminals will be consistent with the operating expenses for our existing pipelines and terminals. We believe that following the acquisition and the completion of Alon’s refinery enhancements, the pipelines and terminals to be acquired from Alon will have, on average, a 55% capacity utilization, although our right to use these pipeline and terminals for customers other than Alon is restricted under the pipelines and terminals agreement. In connection with the acquisition, we expect to hire 10 to 12 employees from Alon to operate these assets. Our existing management personnel will perform management functions with respect to these assets.

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Refined Product Pipelines and Tank Farm

The following table sets forth certain operating data for each of the refined product pipelines that we agreed to acquire. 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. The capacity of the pipelines is 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. Alon is the only shipper on each of these pipelines and we cannot add customers without Alon’s consent.

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.

Big Spring, Texas to Wichita Falls, Texas
The Big Spring to Wichita Falls refined product pipeline was constructed in 1969 and 1989, and consists 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.

Wichita Falls, Texas to Duncan, Oklahoma
The Wichita Falls to Duncan refined product pipeline 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 are not acquiring.

Big Spring, Texas to Orla, Texas
Segments of the Big Spring to Orla refined product pipeline were constructed in 1978 and 1998, and consist of 85 miles of 8-inch pipeline and 50 miles of 10-inch pipeline. This pipeline is used for the shipment of refined products produced at Alon’s Big Spring Refinery from Midland, Texas to the tank farm at Orla, Texas, which is part of the assets to be acquired.

Orla, Texas Tank Farm
The following table outlines the tank farm’s storage capacity, number of tanks, supply source, mode of delivery and average throughput (in bpd) for the fiscal year ended December 31, 2004:

The Orla tank farm receives refined products from Alon’s Big Spring Refinery that accounted for all of its volumes in 2004. Refined products received at this tank farm are delivered into our Orla to El Paso pipeline. Alon is currently the only customer at this tank farm.

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Refined Product Terminals

The following table outlines the location of the refined product terminals that we propose to acquire and their storage capacities, number of tanks, supply source, mode of delivery and average throughput (in bpd) for the year ended December 31, 2004:

Abilene, Texas Terminal
This terminal receives refined products from Alon’s Big Spring Refinery, which accounted for all of its volumes in 2004. 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, Texas Terminal
This terminal receives refined products from Alon’s Big Spring Refinery, which accounted for all of its volumes in 2004. Refined products received at this terminal are sold via a truck rack or shipped to Duncan, Oklahoma. Alon is the only customer at this terminal.

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 2004.

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PART II

Item 5. Market for the Registrant’s Common Units and Related Partnership Matters

Our common limited partner units began trading on the New York Stock Exchange under the symbol “HEP” commencing with our initial public offering on July 8, 2004. The following table sets forth the range of the daily high and low sales prices per common unit, cash distributions to common unit holders and the trading volume of common units for the period indicated.

The distribution for the quarter ended September 30, 2004 was paid on November 19, 2004, and reflects the pro rata portion of the minimum quarterly distribution rate of $.50, covering the period from the closing of the initial public offering through September 30, 2004. A distribution for the quarter ended December 31, 2004 of $.50 was paid on February 17, 2005.

As of February 18, 2005, we had approximately 9,400 common unit holders, including beneficial owners of common units held in street name.

We intend to consider cash distributions to unit holders 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 Senior Secured Revolving Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the revolving credit agreement, occurs or would result form the cash distribution. The indenture relating to our new senior notes will prohibit us from making cash distributions under certain circumstances.

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

Upon the closing of our initial public offering, Holly received 7,000,000 subordinated units. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in its partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner

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interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009.

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

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

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:

The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this item is incorporated by reference into “Item 12. Security Ownership of Certain Beneficial Owners and Management,” of this annual report on Form 10-K.

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Item 6. Selected Financial Data

     The following table shows selected financial information for HEP. This table should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of HEP and related notes thereto included elsewhere in this Form 10-K.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7, including but not limited to the sections on “Liquidity and Capital Resources”, contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I. In this document, the words “we”, “our”, “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership formed by Holly Corporation (“Holly”) and is the successor to Navajo Pipeline Co., L.P. (Predecessor) (“NPL”). On March 15, 2004, we filed a Registration Statement on Form S-1 with the United States Securities and Exchange Commission (the “SEC”) relating to a proposed underwritten initial public offering of limited partnership units in HEP. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

On July 7, 2004, we priced 6,100,000 common units for the initial public offering and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $145.5 million, net of $10.3 million of underwriting commissions. All the initial assets of HEP were contributed by Holly and its subsidiaries in exchange for (A) 7,000,000 subordinated units, representing 49% limited partner interest in HEP, (B) incentive distribution rights (as discussed in Part II, Item 5 — Market for the Registrant’s common units and related unitholder matters), (C) the 2% general partner interest and (D) an aggregate cash distribution of $125.6 million.

The operating subsidiary of HEP, Holly Energy Partners – Operating, L.P., formed in anticipation of the HEP public offering entered into a four-year, $100 million revolving credit agreement with Union Bank of California, as administrative agent and lender, in conjunction with the initial public offering, with an option to increase the amount to $175 million under certain conditions. At closing of the initial public offering, $25 million was drawn under the facility.

The proceeds of the public offering and the $25 million borrowing were used to: establish $9.9 million working capital for HEP, distribute $125.6 million to Holly, repay $30.1 million of short-term debt to Holly, pay $13.8 underwriting commissions and other offering costs, and pay $1.4 million of deferred debt issuance costs related to the revolving credit agreement.

We operate a system of refined product pipelines and distribution terminals primarily in west Texas, New Mexico, Utah and Arizona. We generate revenues by charging tariffs for transporting refined 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 and therefore we are not directly exposed to changes in commodity prices. We serve Holly’s refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement with Holly (“Pipelines and Terminals Agreement”) expiring 2019.

Historical Results of Operations

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

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

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

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 our Pipelines and Terminals Agreement described below under “Agreements with Holly”.

In addition, our historical results of operations reflect the impact of the following acquisitions completed in June 2003:

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:

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

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Agreements with Holly Corporation

Under a 15-year Pipelines and Terminals Agreement we entered into with Holly concurrently with the closing of the initial public offering, Holly pays us fees to transport on our refined product pipelines or throughput in our terminals a volume of refined products that will produce at least $35.4 million of revenue in the first year. This minimum revenue commitment will increase each year at a rate equal to the percentage change in the producer price index, but will not decrease as a result of a decrease in the producer price index. Holly pays the published tariff rates on the pipelines and contractually agreed upon fees at the terminals. The tariffs will adjust annually at a rate equal to the percentage change in the producer price index. The terminal fees will adjust annually based upon an index comprised of comparable fees posted by a 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 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.

Furthermore, if new laws or regulations that affect terminals or pipelines generally are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right to negotiate a monthly surcharge on Holly for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly’s pro rata portion of the cost of complying with these laws or regulations, after we have made efforts to mitigate their effect. We and Holly will negotiate in good faith to agree on the level of the monthly surcharge or increased tariff rate.

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

Historically prior to July 13, 2004, Holly has not allocated any of its general and administrative expenses to its pipeline and terminalling operations. Under the Omnibus Agreement with Holly, we have agreed to pay Holly an annual administrative fee, initially in the amount of $2.0 million, for the provision by Holly or its affiliates of various general and administrative services to us for three years following the closing of our initial public offering. The fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index for the applicable year. In addition, our general partner has the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses. The $2.0 million fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of pipeline and terminal personnel or other employees of Holly Logistic Services, L.L.C. 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 will also reimburse Holly and its affiliates for direct expenses they incur on our behalf. In addition, we anticipate incurring additional general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, annual and quarterly reports to unitholders, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees. Under the Omnibus Agreement, Holly also agreed to indemnify us in an aggregate amount not to exceed $15 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.

Pending Alon Transaction; Senior Note Offering

On January 25, 2005, we entered into a contribution agreement with Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) that provides for our acquisition, subject to the terms and conditions of the agreement, of four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas. These pipelines and terminals transport approximately 70%

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of the light refined products for Alon’s 65,000 bpd capacity refinery in Big Spring, Texas. The total consideration for these pipeline and terminal assets is $120 million in cash and 937,500 of our Class B subordinated units. In connection with the transaction, we will enter into a 15-year pipelines and terminals agreement with Alon. Please read “Pending Alon Transaction” under “Liquidity and Capital Resources” below for additional information.

We anticipate financing the pending Alon transaction through our private offering of $150 million principal amount of 6.25% senior notes previously announced on February 4, 2005 and priced on February 11, 2005. We expect to issue the notes and close the offering and the Alon transaction on or about February 28, 2005. We expect to use the proceeds of the offering to fund the $120 million cash portion of the consideration for the pending Alon transaction, and to use the balance to repay $30 million of outstanding indebtedness under our revolving credit agreement, including $5 million that we plan to draw shortly before the closing of the Alon transaction.

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RESULTS OF OPERATIONS

Operating Income (Loss) and Volumes

The following tables present our operating income (loss) and volume information for the years ended December 31, 2004, 2003 and 2002. Prior to January 1, 2004, we recorded pipeline tariff revenues only on FERC-regulated pipelines and terminal service fee revenues from third-party customers. No revenues from affiliates were recorded on non-FERC regulated pipelines and no terminal services fee revenues from affiliates were recorded for use of our terminal facilities. Commencing January 1, 2004, affiliate revenues have been recorded for all pipeline and terminal facilities included in our pipeline and terminal facilities. As a result, the information included in the following table of operating income (loss) is not comparable on a year-over-year basis.

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Supplemental Data

For the period after completion of our initial public offering on July 13, 2004, HEP results include only those assets contributed from Holly and its subsidiaries to HEP. The reported income for the periods prior to July 13, 2004, include revenues and expenses related to crude oil and intermediate product pipelines that were not contributed to HEP. The following table shows separately our revenue and expense data for (i) the refined product pipeline and terminal assets that were contributed to HEP commencing on July 13, 2004, (ii) the predecessor’s operation of such assets through July 12, 2004, and (iii) the revenues and expenses through July 12, 2004, for the crude oil and intermediate product pipeline assets that were not contributed to HEP by Holly and its subsidiaries.

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Results of Operations – Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Summary

Net income for the year ended December 31, 2004 was $32.5 million, a $31.9 million increase from the $0.6 million for the year ended December 31, 2003, due mainly to the commencement of recording all affiliate revenues beginning January 1, 2004. As a result, we recorded $30.2 million of revenue in 2004 for which no comparable revenues had been recognized in the 2003 period.

We also began consolidating the results of Rio Grande as of July 1, 2003 due to increasing our ownership to 70%. This resulted in $2.0 million more net income in 2004 than in 2003.

The remaining increase in earnings is due to general increased volumes for our pipeline and terminalling services in 2004, the purchase of several new terminals on June 2003, and decreased environmental remediation expenses in 2004.

Revenues

Revenues of $59.9 million from the combined operations of the assets contributed to the Partnership for the year ended December 31, 2004 were $34.0 million higher than the $25.9 million in the comparable period of 2003, primarily as a result of commencement of recording of revenues on intra-company transactions effective January 1, 2004. During the year ended December 31, 2004, revenues from assets not contributed to the Partnership increased to $7.9 million from $4.9 million largely as a result of recording revenues on intermediate product pipelines, which are currently owned by Holly. Refined product shipments on the Partnership’s pipeline system, excluding barrels moved pursuant to a capacity lease agreement, averaged 82.7 thousand barrels per day (“mbpd”) for the year ended December 31, 2004 as compared to 60.7 mbpd for the year ended December 31, 2003, largely as a result of the expansion of the Navajo refinery and the consolidation of Rio Grande in July 2003, when the ownership interest increased to 70%.

Revenues of $12.4 million from terminal and truck loading rack service fees for the year ended December 31, 2004 were $9.8 million higher than the $2.6 million in 2003. Revenues from third parties increased by $0.6 million, largely as a result of the acquisition of the Spokane terminal in June 2003, while affiliate revenues, first recognized in 2004, were $9.2 million. Average volumes of products terminalled in Partnership facilities increased to 139.8 mbpd for the year ended December 31, 2004 from 106.7 mbpd in 2003. In addition to the increase in capacity of the Navajo refinery, the average volume was significantly impacted by the acquisition of the Woods Cross refinery by Holly in June 2003, which resulted in the Partnership’s acquisition of terminals and truck loading facilities in Utah, Idaho and Washington.

Operating Costs

Operating costs decreased $0.6 million from the year ended December 31, 2003 to the year ended December 31, 2004. The expenses for the Lovington crude system (not contributed to HEP) decreased $3.0 million from 2003 to 2004 due to a $1.3 million reduction of environmental remediation and maintenance expenses from 2003 and a $1.7 million decrease because 2004 expenses are only included until HEP’s formation on July 13, 2004. The purchase of the Spokane, Boise and Burley terminals and Woods Cross truck rack in June 2003 added $0.5 million to operating expense for 2004 due to only being included in our operations for seven months in 2003. Increased volumes on our remaining pipelines and terminals added $2.1 million of operating expense for 2004 over 2003, partially offset by exclusion of costs for the intermediate pipelines from July 13, 2004. Finally, our operating costs increased by $1.2 million from 2003 to 2004 as we started consolidating the results of Rio Grande in July 2003.

Depreciation and Amortization

Depreciation and amortization expense was $0.8 million higher in the year ended December 31, 2004 than in year ended December 31, 2003. Of this increase, $1.2 million is due to the consolidation of Rio

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Grande beginning July 1, 2003. There was an offsetting $0.4 million decrease due to the crude system and intermediate pipelines not being contributed to HEP on July 13, 2004.

General and Administrative

General and administrative costs increased $1.9 million, reflecting costs incurred beginning on HEP’s formation date of July 13, 2004. Prior to that date, Holly did not allocate any general and administrative costs to its subsidiaries.

Interest Expense

We recorded $0.7 million of total interest expense during the year ended December 31, 2004, including interest expense on the $25 million outstanding debt, cost of commitment fees for the unused portion of the $100 million revolving credit agreement, and amortization of deferred debt issuance costs. No interest expense was incurred in 2003.

Equity in Earnings of Rio Grande Pipeline Company and Minority Interest

We recorded $0.9 million equity in earnings of Rio Grande in the year ended December 31, 2003, reflecting our 25% ownership during the first half of 2003. Since our acquisition of an additional 45% interest on June 30, 2003, we have included the revenues and expenses of Rio Grande in our consolidated financial statements. The minority interest related to the 30% that we do not own reduced our income by $2.0 million for the year ended December 31, 2004 and by $0.8 million in the year ended December 31, 2003.

Results of Operations – Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Summary

Net income for the year ended December 31, 2003 was $0.6 million, a $2.1 million decrease from the $2.7 million for the year ended December 31, 2002, due mainly to increased environmental remediation expenses in 2003.

Revenues

Revenues increased by $7.2 million from $23.6 million for the year ended December 31, 2002 to $30.8 million for the year ended December 31, 2003, primarily as a result of the consolidation of Rio Grande on June 30, 2003, when we increased our ownership interest from 25% to 70%. During the six months ended June 30, 2003, Rio Grande had been accounted for by the equity method, contributing $0.9 million to net income but no revenues. Rio Grande’s revenues for the six months of 2003 that it was consolidated were $6.9 million from a third party. Pipeline revenues received from Holly decreased by $0.9 million as a result of lower volumes of light products produced at the Navajo Refinery. Third party terminal revenues increased by $1.0 million in 2003, largely as a result of the acquisition of the Spokane terminal in June 2003, which contributed third party revenues of $0.9 million in 2003.

Operating Costs

Operating costs increased by $4.8 million from $19.4 million for the year ended December 31, 2002 to $24.2 million for the year ended December 31, 2003. The consolidation of Rio Grande and acquisition of the Spokane, Burley and Boise terminals and the Woods Cross truck rack accounted for $1.3 million and $0.9 million, respectively, of the increased costs. Operating costs for the pipelines increased $1.0 million in 2003 as compared to 2002 primarily due to a $1.9 million increase in operating costs related to the Lovington crude oil pipelines, reflecting increased pipeline integrity testing and related maintenance expense. The Lovington crude oil pipelines were not contributed to our partnership. Operating costs for terminal facilities decreased $0.3 million in 2003 as compared to 2002, excluding the impact of new

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assets acquired during the year. Property taxes and insurance increased by $0.4 million in 2003 as compared to 2002.

Depreciation and Amortization

Depreciation expense increased $2.0 million from $4.5 million for the year ended December 31, 2002 to $6.5 million for the year ended December 31, 2003, primarily as a result of the consolidation of Rio Grande and, to a lesser extent, additional capital expenditures.

Equity in Earnings of Rio Grande Pipeline Company and Minority Interest

We recorded $0.9 million equity in earnings of Rio Grande in the year ended December 31, 2003, reflecting our 25% ownership during the first half of 2003. The minority interest related to the 30% that we do not own, subsequent to our acquisition of the additional 45% interest, reduced our income by $0.8 million in the year ended December 31, 2003. We recorded $2.7 million equity in earnings of Rio Grande in the year ended December 31, 2002, which reflected our 25% ownership interest for the full year.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Prior to our initial public offering, Holly utilized a common treasury function for all of its subsidiaries, whereby all cash receipts were deposited in Holly bank accounts and all cash disbursements were made from these accounts. Cash receipts from customers and cash payments to vendors for NPL were recorded in these common accounts. Thus, prior to our initial public offering, no cash balances were reflected in the accounts of NPL other than the cash balances of Rio Grande. Cash transactions handled by Holly for NPL were reflected in accounts receivable from affiliates and accounts payable to affiliates. Holly did not contribute these affiliate payables and receivables balances to HEP.

We completed our initial public offering of 7,000,000 common units of HEP on July 13, 2004, realizing net proceeds of $145.5 million. Concurrent with the closing of the offering we entered into a four-year $100 million revolving credit facility agreement and borrowed $25 million under the agreement. The proceeds from the public offering and the borrowings were used to (1) pay offering costs of $3.5 million and deferred debt issuance costs of $1.4 million, (2) repay $30.1 million of debt we owed to Holly and (3) make a $125.6 million distribution to Holly. We retained $9.9 million to replenish working capital.

Upon completion of our initial public offering, we had $9.9 million of working capital exclusive of the $25 million drawn on our revolving credit agreement and any working capital of Rio Grande. We now have $75 million available and unused under our revolving credit agreement. We believe our current cash balances, future internally-generated funds and funds available under our revolving credit agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.

In November 2004, we paid our first regular cash distribution for the third quarter of 2004 of $0.435 per unit, based on the minimum quarterly cash distribution of $0.50 prorated for the period since the initial public offering on July 13, 2004. The distribution was paid on all common and subordinated units and the general partner interest, and the aggregate amount of the distribution was $6.2 million. In February 2005, we paid a cash distribution for the fourth quarter of 2004 of $0.50 on all units and the general partner interest, and the aggregate amount of the distribution was $7.1 million.

Cash Flows — Operating Activities

Cash flows from operating activities increased by $10.0 million from $5.9 million for the year ended December 31, 2003 to $15.9 million for the year ended December 31, 2004. Net income for 2004 was $32.5 million, an increase of $31.9 million from $0.6 million for 2003. The non-cash items of depreciation and amortization, minority interest, and equity in earnings of Rio Grande increased $2.9 million in 2004 from 2003. Working capital items decreased cash flows by $25.9 million during 2004, primarily due to

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$31.7 of current assets and liabilities of NPL that were not contributed to HEP upon formation in July 2004, as compared to a decrease in cash flows of $1.0 million in 2003. Most of the non-contributed working capital pertained to receivables for the affiliate revenues that were first recorded in 2004 and payables for inter-company expenses.

Cash flows from operations for the year ended December 31, 2003 increased $1.6 million to $5.9 million from $4.3 million for the year ended December 31, 2002. Cash flows from operations for the year ended December 31, 2003 increased primarily due to an increase in non-cash items consisting of the following: (i) an increase in depreciation of $2.0 million; (ii) the reduction in equity in earnings of $1.8 million; and (iii) an increase in minority interest of $0.8 million when compared to the year ended December 31, 2002. However, net income for the year ended December 31, 2003 decreased by $2.1 million. Working capital items decreased cash flows by $25.9 million during 2003, as compared to a decrease in cash flows of $0.1 million in 2002.

Cash Flows — Investing Activities

Cash flows used for investing activities decreased from $29.3 million for the year ended December 31, 2003 to $6.2 million for the year ended December 31, 2004. Investment in properties and equipment for 2004 were $3.0 million. We also distributed $3.2 million to minority interests in Rio Grande during the year ended December 31, 2004. During 2003, we acquired a 45% interest in Rio Grande for $21.2 million, net of cash acquired.

During the year ended December 31, 2003 $6.8 million was expended on capital assets, including $3.4 million by Rio Grande subsequent to June 30, 2003 and $1.4 million in connection with the acquisition of the Boise, Burley and Spokane terminals and the Woods Cross truck rack. An additional $1.9 million was expended on maintenance capital projects and/or construction in progress during the year ended December 31, 2003. In 2003, Rio Grande made cash distributions of $4.5 million to its owners subsequent to June 30, 2003, of which $1.4 million is reflected as a cash outflow in investing activities.

Capital expenditures were $6.8 million in the year ended December 31, 2002. These expenditures related primarily to additions to the intermediate product pipelines (which were not contributed to our partnership) and the terminals in Moriarty and Bloomfield, New Mexico. We received cash distributions from Rio Grande of $2.5 million in 2002.

Cash Flows — Financing Activities

We completed our initial public offering of 7,000,000 common units on July 13, 2004, receiving net proceeds of $145.5 million and drawing $25 million on our revolving credit agreement. The proceeds from these financings were utilized to repay $30.1 million owed to Holly as well as making a $125.6 million distribution to Holly. In addition, we used $3.5 million to pay for offering costs and $1.4 million to pay deferred debt issuance costs associated with our revolving credit agreement. We retained $9.9 million to replenish working capital. Subsequent to our initial public offering, we made distributions to our unitholders of $6.2 million. Additionally, we paid $0.7 million in late 2004 in deferred debt issuance costs relating to the financing of the pending Alon transaction.

Effective June 30, 2003, we acquired an additional 45% equity interest in Rio Grande. On June 1, 2003, we acquired the Boise, Burley and Spokane terminals and the Woods Cross truck rack. These acquisitions were financed by a $30.1 million non-interest bearing loan from Holly, repaid in July 2004.

Capital Requirements

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operations regulations. Our capital requirements have consisted of, and are expected to continue to consist primarily 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

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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.

Prior to our initial public offering, our capital requirements had historically been met with internally generated funds including short-term non-interest bearing funding from affiliates. We have budgeted average annual maintenance capital expenditures for our existing operations of $1.5 million in 2005 (excluding approximately $0.5 million of maintenance capital expenditures we anticipate with respect to assets to be acquired in the pending Alon transaction). We anticipate that these capital expenditures will be funded with cash generated by operations. However, we anticipate funding future expansion capital requirements through long-term borrowings or other debt financings and/or equity capital offerings. See “Credit Agreement” below for information related to the revolving credit agreement we entered into in July 2004.

Credit Agreement

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100 million senior secured revolving credit agreement (the “Credit Agreement”). Union Bank of California, N.A. is a lender and serves as administrative agent under this agreement. Upon closing of our initial public offering, we drew $25 million under the Credit Agreement, which was outstanding at December 31, 2004.

The Credit Agreement is available to fund capital expenditures, acquisitions, working capital and for general partnership purposes. Advances under the Credit Agreement that are designated for working capital will be short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50 million sub-limit. Up to $5 million is available to fund distributions to unitholders.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $175 million. Such requests will become effective if (i) certain conditions specified in the Credit Agreement are met and (ii) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

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

We may prepay all loans at any time without penalty. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the agreement. The initial $25 million borrowing is not a working capital borrowing under the Credit Agreement and is classified as a long-term liability. As the borrowing is not designated as a working capital borrowing, we may, at our option, extend and renew this borrowing.

Indebtedness under the Credit Agreement bears interest, at our option, at either (i) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (ii) at a rate equal to LIBOR plus an applicable margin (ranging from 1.50% to 2.25%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate of 0.375% or 0.500% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. The agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

The Credit Agreement imposes certain requirements, including: prohibition against distribution to

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unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of certain levels of tangible net worth, EBITDA to interest expense ratio, and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

We expect to amend our credit agreement prior to the closing of the pending Alon transaction and the related senior notes offering in order to allow for these events as well as to amend certain of the restrictive covenants.

Pending Alon Transaction

On January 25, 2005, we entered into a contribution agreement with Alon that provides for our acquisition, subject to the terms and conditions of the agreement, of four refined products pipelines aggregating approximately 500 miles, an associated tank farm and two refined products terminals with aggregate storage capacity of approximately 347,000 barrels. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s 65,000 bpd capacity refinery in Big Spring, Texas.

The total consideration for these pipeline and terminal assets is $120 million in cash and 937,500 of our Class B subordinated units. We anticipate financing the pending Alon transaction through our private offering of $150 million principal amount of 6.25% senior notes previously announced on February 4, 2005 and priced on February 11, 2005. We expect to issue the notes and close the offering on or about February 28, 2005. We expect to use the proceeds of the offering to fund the $120 million cash portion of the consideration for the pending Alon transaction, and to use the balance to repay $30 million of outstanding indebtedness under our Credit Agreement, including $5 million that we plan to draw shortly before the closing of the Alon transaction. In connection with the Alon transaction, we will enter into a 15-year pipelines and terminals agreement with Alon. Under this agreement, Alon will agree to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to us of $20.2 million per year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipeline and terminals taking into account a 5,000 BPD expansion of Alon’s Big Spring Refinery expected to be completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. We will grant Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have a right of first refusal to purchase the pipelines and terminals if we decide to sell them in the future. Additionally, we will enter into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals to be acquired from Alon, where Alon will indemnify us subject to a $100,000 deductible and a $20 million maximum liability cap.

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Contractual Obligations and Contingencies

The following table presents our long-term contractual obligations as of December 31, 2004. Our operating lease contains one 10-year renewal option that is not reflected in the table below and that is likely to be exercised.

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2004, 2003 and 2002.

Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. These laws and regulations are subject to 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. However, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures, we will be able to recover a portion of the cost from Holly. See “Agreements with Holly Corporation” for further discussion. 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 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 has agreed to indemnify us in an aggregate amount not to exceed $15 million for ten years after the closing of the initial public offering for environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before the closing date.

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our 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.

We may experience future releases of refined products into the environment from our pipelines and terminals, or discover historical releases that were previously unidentified or not assessed. While we maintain an extensive inspection and audit program designed, as applicable, to prevent and to detect and

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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.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals, except that prior to January 1, 2004 pipeline tariff and terminal services fee revenues were not recorded on services utilizing non-FERC regulated pipelines. These revenues had not previously been recognized as the pipelines and terminals were operated as a component of Holly’s petroleum refining and marketing business. Commencing January 1, 2004, we began charging Holly pipeline tariffs and terminal service fees in the amounts set forth in the Pipelines and Terminals Agreement. Additional pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in the capacity of one of our pipelines.

The only revenues reflected in the historical financial data prior to January 1, 2004 are from (i) third parties who used our pipelines and terminals, (ii) Holly’s use of our FERC-regulated pipeline and (iii) Holly’s use of the Lovington crude oil pipelines, which were not contributed to us.

Long-Lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results, and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2004 and 2003.

Contingencies

It is common in our industry to be subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these types of matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these types of contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.

The Omnibus Agreement also provides that Holly will indemnify us up to $15 million for certain environmental matters for a ten-year period beginning July 13, 2004.

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Recent Accounting Pronouncement

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 123 (revised), “Share-Based Payment.” These revisions require a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value award with the cost being recognized over the period in which the employee is required to provide service in exchange for the award. The fair value of the award will be remeasured subsequently at each reporting date through the settlement date. Changes in fair value during the service period will be recognized as compensation cost over the remaining service period. This standard will be effective for us for the first interim period beginning after June 15, 2005. We do not believe the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows.

ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS

Risks Inherent In Our Business

We depend upon Holly and particularly its Navajo Refinery for a majority of our revenues, and if those revenues were reduced, there would be a material adverse effect on our results of operations.

For the year ended December 31, 2004, Holly accounted for 60.1% of the revenues of our refined products pipelines and 74.3% 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 Pipelines and Terminals Agreement 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, result in our realizing materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2004, production from the Navajo Refinery accounted for 83.7% of the throughput volumes transported by our pipelines that serve the Navajo Refinery. Operations at the Navajo Refinery could be partially or completely shut down, temporarily or permanently, as the result of:

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The magnitude of the effect on us of any shutdown will 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, labor relations, environmental remediation and capital expenditures, and 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 Pipelines and Terminals Agreement 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 Pipelines and Terminals Agreement. 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. In addition to revenues received from Holly under its Pipelines and Terminals Agreement, we derived 9.6% of our revenues for the year ended December 31, 2004 from a contract with Alon, which leases 20,000 bpd of capacity on our Artesia-Orla-El Paso pipeline. If the pending Alon pipelines and terminals agreement had been in place January 1, 2004, and Alon had met its minimum volume commitment to us, Alon would have generated approximately $26.7 million, or 33.4%, of what our pro forma revenues would have been for the year ended December 31, 2004. In addition, a subsidiary of 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 18.4% of our revenues for the year ended December 31, 2004. During the first quarter of 2005 based on the aggregate volumes shipped by BP, we expect that BP will no longer be required to pay the border crossing fee pursuant to its contract. For the year ended December 31, 2004, the border crossing fee paid by BP to Rio Grande was $4.5 million or 6.6% of our revenues.

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, including the Longhorn Pipeline, 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 face competition from other pipelines that may be able to supply our shippers’ end-user markets with refined products on a more competitive basis. One particular pipeline, the Longhorn Pipeline, could provide significant competition. The Longhorn Pipeline is a common carrier pipeline that is capable of delivering refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. If the Longhorn Pipeline operates as currently proposed, it could result in significant downward pressure on wholesale refined product prices and refined product margins in El Paso and related markets. Additionally, the increased supply of refined products from Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and the likely increase in the demand for shipping product on the interconnecting common carrier pipelines, which are currently capacity constrained, could cause a decline in the demand for refined product from Holly or Alon. For Holly, this could ultimately result in a reduction in Holly’s minimum revenue commitment to us, and while the pending pipelines and terminals agreement with Alon does not provide for a reduction in its minimum volume commitment obligation in these circumstances, it could reduce our opportunity to earn revenue from Alon in excess of Alon’s minimum volume commitment obligation.

An additional factor that could affect some of Holly’s and Alon’s markets is excess pipeline capacity from

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the West Coast into our shippers’ Arizona markets on the pipeline from the West Coast to Phoenix. If refined products become available on the West Coast in excess of demand in that market, additional products could be shipped into our shippers’ Arizona markets with resulting possible downward pressure on refined products prices in 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. 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 they 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 adversely be 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 three to six years. BP’s agreement to ship on the Rio Grande Pipeline expires in 2007.

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.

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Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

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

Holly, Alon and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these 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 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, either as a result of the operation of the Longhorn Pipeline or otherwise, could further exacerbate such constraints on deliveries to Arizona. Any reduction in volumes transported in our pipelines or through our terminals would adversely affect our revenues.

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:

If our assumptions about growth in market demand prove incorrect, Holly may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy. Furthermore, Holly is under no obligation to pursue a growth strategy. If Holly chooses not to, or is unable to, gain additional customers in new or existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth strategy would be adversely affected. Moreover, Holly may not make acquisitions that would provide acquisition opportunities to us, or if those opportunities arose, 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

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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 by a percentage equal to the 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 Energy Policy Act adopted in 1992, our interstate pipeline rates were deemed just and reasonable or “grandfathered.” As that Act applies to our rates, a person challenging a grandfathered rate must, as a threshold matter, establish that a substantial change has occurred since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, 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 has agreed and Alon will agree not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements. These agreements do not prevent other current or future shippers from challenging our tariff rates.

Potential changes to current petroleum pipeline rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future.

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

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

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

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possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

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

An adverse decision in a lawsuit pending between Holly and Frontier Oil Corporation could have a material adverse effect on Holly’s financial condition and therefore on our results of operations.

On August 20, 2003, Frontier Oil Corporation filed a lawsuit in the Delaware Court of Chancery seeking declaratory relief and unspecified damages based on allegations that Holly repudiated its obligations and breached an implied covenant of good faith and fair dealing under a merger agreement announced in late March 2003 under which Frontier and Holly were to be combined. On September 2, 2003, Holly filed its answer and counterclaims seeking declaratory judgments that Holly had not repudiated the merger agreement, that Frontier had repudiated the merger agreement, that Frontier had breached certain representations made by Frontier in the merger agreement, that Holly’s obligations under the merger agreement were and are excused and that Holly may terminate the merger agreement without liability, and seeking unspecified damages as well as costs and attorneys’ fees. The trial with respect to Frontier’s complaint and the Holly answer and counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. In this litigation, the maximum amount of damages currently asserted by Frontier against Holly is approximately $161 million plus interest and the maximum amount of damages currently asserted by Holly against Frontier is approximately $148 million plus interest. Post-trial briefing was completed in late April 2004; and on May 4, 2004, the court heard oral argument. We expect a decision to be announced by the court within several months. While we cannot predict the outcome of this litigation, an adverse decision to Holly could have a material adverse effect on Holly’s business, financial condition, liquidity, competitive position or prospects. Because we depend upon Holly for a majority of our revenues, if an adverse decision to Holly reduced the volumes it transports on our pipelines or its ability to make payments to us under its Pipelines and Terminals Agreement, our results of operations and financial condition could be materially adversely affected.

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, 2004, pro forma for the pending Alon transaction and the issuance of the 6.25% Senior Notes, our total outstanding long-term debt, including current maturities, would have been approximately $150 million. Various limitations in our revolving credit agreement and the indenture for the 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 revolving 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

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investments and granting liens. Additionally, upon completion of the pending Alon transaction our contribution agreement with Alon will restrict us from selling the pipelines and terminals to be acquired from Alon and from prepaying more than $30 million of the 6.25% senior notes for ten years, 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.

Risks Related To the Pending Alon Transaction

We may not be able to realize the expected benefits of our pending acquisition of Alon’s pipelines and terminals.

Our expectations regarding the revenues and operating cash flow resulting from our pending acquisition of Alon’s pipelines and terminals may prove to be incorrect. Pursuant to the pipelines and terminals agreement we will enter into with Alon, Alon is obligated to transport on these pipelines and to deliver at these terminals approximately 90% of its recent usage of these pipelines and terminals, taking into account a 5,000 bpd expansion of Alon’s Big Spring Refinery expected to be completed in February 2005, in order to meet its minimum volume commitment. If Alon transports or delivers volumes in amounts equal only to its minimum volume commitment or if Alon is unable to meet its minimum volume commitment for any reason, our revenues and operating cash flow from these assets will be lower than expected. Furthermore, we will be required to obtain Alon’s consent to any third-party shipments on these assets. Even if we obtain Alon’s consent, we may not be able to generate significant additional throughput on these assets from third parties other than Alon because the competitive pressures in the markets served by these assets may be greater than anticipated. As a result, our revenues and operating cash flow could be adversely affected.

Subject to Alon’s minimum volume commitment, the Alon pipelines and terminals agreement does not require Alon to transport its refined products through the pipelines and terminals that we will acquire from them. It also does not prohibit Alon from constructing new pipelines or using pipelines owned by others to transport its refined products.

We may also face difficulties operating these assets on an efficient basis, resulting in significantly higher costs to us than anticipated and thus adversely affecting our revenues and operating cash flow. During the transition of operational control of the assets from Alon to us, we may experience unforeseen operating difficulties, including difficulties (1) integrating the technological and management standards, processes, procedures and controls of these assets with those of our existing operations; (2) managing the increased scope, geographic diversity and complexity of our operations; and (3) mitigating contingent and/or assumed liabilities.

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

Alon is already one of our significant customers. If Alon’s pipelines and terminals agreement had been in place January 1, 2004, and Alon had met its minimum volume commitment to us, Alon would have generated approximately $26.7 million, or 33.4%, of pro forma revenues for the year ended December 31, 2004.

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 including:

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The magnitude of the effect on us of any shutdown will 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, planned shutdowns of individual process units within the refinery to perform major maintenance activities, also referred to as “refinery turnarounds,” labor relations, environmental remediation and capital expenditures.

In addition, the pipelines and terminals agreement we will enter into with Alon provides that 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.

RISK MANAGEMENT

At December 31, 2004, we had outstanding secured debt of $25.0 million. As the interest rates on our credit facility borrowings are reset frequently based on either the bank’s daily effective prime rate or a LIBOR rate, interest rate market risk on the fair value of our debt is low. A ten percent change in the market interest rate over the next year would not materially impact our financial condition, earnings or cash flows.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, subject to certain deductibles. Holly has business interruption insurance for the benefit of its refinery assets. Payments Holly is required to make pursuant to its minimum revenue commitment would be recoverable to Holly under its policy in the event of an insurable loss at its facilities. In addition, we maintain our own business interruption insurance for the benefit of our pipelines and terminals, that would allow us to recover losses due to interruption at our customers’ facilities that affect our revenue. We are not fully insured against certain risks because such

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risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is interest rate risk associated with our revolving credit agreement. Debt under our existing revolving credit agreement will bear interest at a variable rate based on LIBOR. We are not now utilizing, but we may in the future utilize, derivative instruments to hedge our exposure to interest rates.

Since we do not own products shipped on our pipelines or terminalled at our terminal facilities we do not have market risks associated with commodity prices.

Item 8. Financial Statements and Supplementary Data

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Holly Logistic Services, L.L.C.
and Unitholders of Holly Energy Partners, L.P.

We have audited the accompanying consolidated balance sheets of Holly Energy Partners, L.P. (the “Partnership”) as of December 31, 2004 and 2003, and the related consolidated statements of income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Energy Partners, L.P. at December 31, 2004 and 2003, and the consolidated results of operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

Dallas, Texas
February 21, 2005

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Holly Energy Partners, L.P.

See accompanying notes.

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Holly Energy Partners, L.P.